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 Canada’s 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)


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)


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)


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. 


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


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.


  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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Oil & Gas M&A Reaches US$33.4 Billion in Q1 2014

Posted by Eoin Coyne

Apr 3, 2014 7:35:00 AM

The recent absence of major Chinese involvement and eroding profitability in the oil and gas industry has led to M&A reaching just $33.4 billion in Q1 2014, 28% lower than the average quarterly M&A spend over the past three years. The lower M&A value is also mirrored in the deal count of 205 deals during the quarter (excluding licensing rounds) which is 27% lower than the average deal count by quarter since 2010.

Chinese Companies Uncharacteristically Quiet

Since the start of 2010, state-influenced Chinese companies have been responsible for $95 billion of company-to-company oil and gas deals at an average spend of $5 billion per quarter. In Q1 2014, these companies accounted for only $147 million of upstream deals. It is likely that this relatively low amount of activity is more to do with a timing issue, rather than a shift in strategy from China, especially with Chinese companies rumoured to be interested in acquiring large stakes in the LNG industries of Canada's west coast and Cyprus during the quarter.

Lower Industry Profitability Feeds Through to Lower M&A Spend

The more significant factor in the relatively lower M&A total is likely to be the continued drop in profits for the upstream industry as a whole. At the time of publication, 200+ companies had reported their 2013 annual results. Using the Evaluate Energy database, it can be seen that the 2013 normalised profits are 25% lower than in 2011 and 16% than 2012. The underlying reason behind the erosion of profits is the escalation of operating and development costs in the oil and gas industry, which haven’t been reflected in the oil and gas price realisations. Therefore, profits and free cash flow have been squeezed and companies have been more tentative with their capex budgets.

M&A Deal Value and Count by Quarter and Company Type


Source: Evaluate Energy M&A Database

L1 Energy Acquires RWE-DEA in Biggest Deal of the Quarter

Despite the lower than average outlay, the quarter was boosted by the largest deal for the past 15 months when L1 Energy acquired RWE-DEA for $7.1 billion. To find a larger deal than this we have to go back to December 2012, when Freeport-McMoRan Copper & Gold Inc acquired Plains Exploration & Production for $16.3 billion.

L1 Energy is a privately-owned investment vehicle, owned primarily by Mikhail Fridman, the second richest man in Russia. The board can boast the inclusion of the ex-CEO of BP, Lord Browne, and Stan Polovets, the CEO of the Alfa-Access-Renova Consortium, which owned a 50% stake in TNK-BP prior to Rosneft’s acquisition of the company in 2012. L1 Energy will be gaining oil and gas interests in 14 different countries with this acquisition and it is likely that more deals will follow; the company has pledged to invest $20 billion or more in oil and gas assets across the world.

For RWE, the sale comes at a time when company profits – derived in majority from its German utilities business – are being hit by Germany’s preferential treatment of renewable energy that has pushed electricity prices down. This sale is a bid to pay down a portion of its large net debt position.

Canadian M&A Picks Up

2013 represented a sluggish year for upstream acquisitions in Canada with $12.1 billion of deals (versus $47 billion during 2012).  2014 has started more brightly with the second largest acquisition of the quarter and $6.2 billion of acquisitions in total. Canadian Natural Resources reached a deal with Devon Energy to acquire Devon’s conventional assets in Canada, excluding its Horn River and heavy oil properties. The motivation for Devon to divest these assets is the need to pay off debt following the company’s largest ever deal last year, when they acquired the Eagle Ford assets of GeoSouthern Energy for $6 billion. Canadian Natural Resources will be receiving 272 million boe of proven reserves, weighted 70% towards liquids at just $11.47 per boe.

The third largest deal of the quarter also involved two Canadian-listed companies when Baytex Energy acquired Aurora Oil & Gas Limited for $2.3 billion. Aurora Oil & Gas is a company based in Australia but with assets primarily in the Eagle Ford play of Texas. The deal represents Baytex Energy’s entry into the Eagle Ford play; the company is looking to bolster its oil-producing operations in the Peace River and Lloydminster Heavy Oil areas and the North Dakota Bakken and Three Forks plays.

For Evaluate Energy's Review of the Major Canadian Deals in 2013, click here

Energy XXI Acquires Fellow Gulf of Mexico Company EPL Oil & Gas Inc

Energy XXI’s acquisition of EPL Oil & Gas and a Central Area Gulf of Mexico licensing round pushed spending in the Gulf of Mexico region to $4 billion during the quarter, accounting for 30% of the total spend in the United States. Energy XXI’s $2.3 billion acquisition of EPL represents an acquisition within their comfort zone in terms of the resources being acquired. EPL Oil & Gas, just like Energy XXI, specialises in oil production around the Gulf of Mexico shelf and coast. In terms of the size of acquisition however, Energy XXI will have to digest a company who has an enterprise value 1.4x greater than Energy XXI’s market capitalisation and will lead to an increase of their already high level of debt that currently stands at 50% greater than their equity value.

In the Gulf of Mexico licensing round 231, most of the headlines centred around BP’s involvement. This round represented the first Gulf of Mexico round that BP could take part in since their federal contracting ban in the wake of the deepwater Horizon spill. Despite the headlines, BP’s $41.6 million outlay represented less than 5% of the total winning bids of $851 million. Freeport-McMoRan Copper & Gold Inc’s involvement represented their debut in any licensing round since entering into the oil and gas sector in 2012 and they ended up being the highest spenders with their winning bids totalling $321 million.

For Evaluate Energy's Review of the Major US Deals in 2013, click here

Top 10 Deals of Q1 2014



Brief Description

Total Acquisition Cost ($ billion)

LetterOne Group


LetterOne Group, via its subsidiary L1 Energy acquires RWE-DEA AG


Canadian Natural Resources Limited

Devon Energy Corporation

Canadian Natural Resources Limited acquires Devon Canada's Canadian conventional assets, excluding its Horn River heavy oil properties


Baytex Energy Corp.

Aurora Oil & Gas Limited

Baytex Energy Corp. acquires Aurora Oil & Gas Limited


Energy XXI

EPL Oil & Gas, Inc.

Energy XXI acquires EPL Oil & Gas, Inc.




Occidental Petroleum Corporation disposes it's Hugoton Field assets


Brightoil Petroleum (Holdings) Limited

Anadarko Petroleum Corporation

A wholly-owned subsidiary of Brightoil Petroleum (Holdings) Limited acquires Anadarko's Chinese subsidiary which owns non-operating interest in the Bohai Bay field, China


Qatar Petroleum

Royal Dutch Shell

Qatar Petroleum acquires a 23% interest in the Parque das Conchas (BC-10) project from Royal Dutch Shell


American Energy Partners, LP

Hess Corporation

American Energy Partners, LP acquires approximately 74,000 acres of dry gas acreage in the Utica Shale from Hess Corporation


Oil Search

Pac LNG Group Companies

Oil Search acquires a 22.835% interest in PRL 15, containing the Elk/Antelope gas discoveries from Pac LNG Group Companies


YPF Sociedad Anonima

Apache Corporation

YPF Sociedad Anonima acquires Apache's operations in Argentina


This report was created using the Evaluate Energy M&A Database, which has tracked every E&P deal including licensing rounds since 2008. Evaluate Energy also holds financial and operating data for 300+ of the world's biggest oil and gas companies. To find out more about Evaluate Energy, Download a Brochure or Request a Demo.


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Why Major Oil Must Change Direction

Posted by Richard Krijgsman

Mar 28, 2014 12:03:00 PM

Early data coming from the Major oil companies gives some ominous pointers to the need for big oil to change direction. In a nutshell, these companies are being squeezed by lower revenues on the one hand and higher costs on the other. There are already signs that these companies are trimming costs and capex but the pace of the new direction may need to pick up. The analysis is based on the latest financial and operating performance data for Major oil companies' upstream operations tracked by Evaluate Energy. This report focuses on the annual results of BP, Shell, ExxonMobil and Chevron. Total has not yet released its detailed operating performance data.

Revenue is feeling the pinch as oil and gas prices have weakened during the year and production volumes have fallen for all the Majors, with the exception of Shell.


Source: Evaluate Energy 

At the same time, costs have been rising; lifting costs rose 10% during 2013 for this group of Majors:


Source: Evaluate Energy, For an in-depth, specific look into US shale production costs, click here

Exploration costs - especially for Shell - continued to rise:


Source: Evaluate Energy 

Development costs have continued to soar. Development costs for oil and gas per barrel of oil equivalent produced have almost doubled to over $45 per boe since 2009:


Source: Evaluate Energy 

This has all inevitably led to a continued slump in upstream earnings:


Source: Evaluate Energy 

Amidst the euphoria of the US shale revolution, it's interesting that the amount of profit generated by the Majors in the US and Canada has been steadily shrinking - so much so, in fact, that European earnings are now comparable to profits flowing from the US, while Asia and Africa have overtaken North America as the largest single sources of earnings. In 2013, part of this was due to big impairments of upstream properties in the US; for most of the Majors, the level of impairments was similar to 2012 but for Shell it was much bigger in 2013 at around $3 billion.

For an in-depth look into US shale production costs, click here


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US Shale Oil Production Costs on the Rise

Posted by Mark Young

Mar 27, 2014 12:37:00 PM

It wasn’t too long ago that a high oil price and a falling gas price prompted many companies to abandon plans to develop major positions in shale gas plays and turn their attentions to the more lucrative shale oil deposits around the country. According to a new analysis of 2013 annual data from 20 US shale gas and shale oil producers by Evaluate Energy, more and more of the companies that made this move could be vulnerable to rising costs in the near future, if the oil price should fall.

To show this, Evaluate Energy has selected 20 representative US companies whose production is either mostly or entirely from US shale gas or shale oil plays.

To download a free pdf with details of these 20 companies’ US shale acreage positions, as well as performance metrics, click here.

The production costs per barrel of oil equivalent (boe) for each company in the group is shown in the following graph:


Source: Evaluate Energy. The companies are sorted in order of the percentage of total US production that is made up by oil in 2013, starting with CONSOL Energy and Southwestern Energy, both at 0% oil, and ending with Northern Oil & Gas at 90% oil. Download a free pdf with US shale data for these 20 companies here. Production costs per boe includes production taxes and transportation costs where reported separately, as some companies combine all of these costs into one item.

It is clear from the graph that those companies producing mainly oil from shale plays have higher costs to contend with. The companies on the right hand side of the graph (those in orange) are all exclusively producing from the Bakken play and Magnum Hunter – the highest cost per boe of the “oil & gas” group – produces roughly 50% of its output in this play.

Overall, it is clear that oil producing plays cost more to operate in than gas plays on a per boe produced basis. Evaluate Energy’s annual results of operations data for the 14 out of 20 companies in the group whose 2013 production is oil-weighted or whose production weighting has shifted significantly in the last 4 years towards oil shows that production costs in shale oil plays are also trending upwards rather than coming down:


Source: Evaluate Energy. Production costs per boe includes production taxes and transportation costs where reported separately, as some companies combine all of these costs into one item.

The oil producing companies who make up the above graph all show an increase in production costs per boe produced from 2012 to 2013. Magnum Hunter is the only company here to show an overall downward trend over the entire 4 year period and this is due to the fact that the company’s high costs in 2010 and 2011 forced a rethink in strategy; the company sold its Eagle Ford oil-producing assets and thus afforded more weight to its gas-producing assets in the Marcellus play. Full analysis of Magnum Hunter’s strategy upheaval and how it has benefited the company is available in this article. These rising costs in shale oil plays revolve around the need or desire to keep increasing production and revenues with wells that only produce attractively for a very short period of time; efforts are needed to maintain economic production in existing wells for as long as possible, whilst all the time constantly drilling new ones.

However, these high and rising costs have only seen a handful of companies alter strategies away from certain plays so far. Two examples of this are Magnum Hunter and Resolute Energy, who sold its Bakken position for $70.1 million in Q2 2013 to focus on its Permian and Powder River basin properties. BP, albeit not a huge US shale acreage holder by any means, has seen fit to spin off its US onshore business segment into a separate company, in order to try and manage the costs and other difficulties this seemingly unique operating environment represents.

On the whole, however, companies appear to be happy to continue bearing the burden of these rising costs, as withdrawals and restructures have been few and far between. This is solely due to the fact that the margins are still there; in fact, margins per boe produced (revenue per boe less production costs per boe) have generally increased for each of the oil producers year-on-year since 2010 despite rising costs, whilst gas producers have seen a general downward trend.


Source: Evaluate Energy – “Margin per boe” in this graph is calculated by taking the US Sales Revenue per boe produced and subtracting the US Production cost per boe for each company. Production costs per boe includes production taxes and transportation costs where reported separately, as some companies combine all of these costs into one item.

Of course, while the margins are still there and increasing, the oil producing companies will not be overly concerned in the short-term by rising costs. Any fall in oil price, however, could leave them vulnerable in the long-term if they do not find a way to drive these rising costs down soon, so expect a full-scale offensive on cost-saving efficiencies by shale oil producers in the US to accompany their drilling programmes in the coming years.

Download a free pdf with the US shale data for the 20 companies in this report here.

This report was created using the Evaluate Energy oil and gas company database, which holds historic financial and operating data and performance metrics for 300+ of the world’s biggest oil and gas companies. Evaluate Energy also tracks company net acreage positions, average well costs and capital expenditure guidance on a play-by-play basis for all the major US and Canadian shale gas and shale oil plays. For more on the Evaluate Energy product, download our brochure or request a demonstration.

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Magnum Hunter Resources Adjusts US Shale Plans for Sustainable Growth

Posted by Mark Young

Mar 11, 2014 9:46:00 AM

New Database Addition Bolsters Evaluate Energy’s Coverage of US Shale Gas & Liquids Industry

Magnum Hunter Resources (NYSE:MHR, “MHR”) is a US-shale focused oil and gas company based in Houston, Texas, and is a new addition to the Evaluate Energy company database. It is one of many US-shale companies that have been forced into a refocus of strategy as operating costs have remained high over the last few years in the major plays. However, MHR has come out of this restructuring looking much healthier and is now set for a spectacular 2014 according to early guidance figures.

Market Cap Doubles in 6 Months

MHR’s 2013 annual results boasted a doubling in market cap since June. This leap followed a difficult period that began for many US shale-focused companies in the middle of 2012, where MHR’s share price fell from US$6.41 to US$4.18 in 3 months and moved further towards $3.50 until June 2013.


Source: Evaluate Energy

The MHR shareholders will be hoping this rise in market cap is sustainable, unlike a similar rise between Q3 2011 and Q1 2012 that eventually led to a fall. Whilst the share price continued to trend downwards in the year between June 2012 and June 2013, the company’s daily production actually went in the opposite direction, proving that a rise in production in isolation is not necessarily a good thing for an oil and gas company shareholder.

A Refocus in Strategy to Maintain Growth

The rise in share price and market cap in 2013 came after a big sale in the Eagle Ford shale in Texas; MHR sold its holdings in Gonzalo and Lavaca counties for $401 million in April to Penn Virginia (NYSE:PVA). MHR completed its exit from the play in early 2014 with the $24 million sale of its remaining Eagle Ford acreage to New Standard Energy (ASX:NSE). This was in some ways a surprising move as the Eagle Ford has been the most active shale play in terms of companies acquiring new or bolstering existing acreage positions over the last few years; MHR is almost unique (especially for a company of its size) in actually leaving the play to focus its efforts elsewhere, but the rise in share price is proof that the market welcomed the move.

The exit from the Eagle Ford, around $100 million of other sales in the year and further planned non-core divestitures of over $400 million have allowed Magnum Hunter to focus its investment plans on its core plays, the Bakken in North Dakota and the Marcellus and Utica plays in the Appalachian basin.

Play Name

MHR - Net Acres Held







Source: Evaluate Energy, correct as of MHR 10-K Annual Report 2013

The asset divestitures were very important moves for MHR, as drilling activity in US shale plays does not seem to be getting cheaper at all, as the years go by. Certain companies, such as Range Resources Corp. (NYSE:RRC) in the Marcellus and Continental Resources (NYSE:CLR) in the Bakken, are finding ways to drive their average well costs down following extensive work over a long period of time, but on the whole, average costs for the last three years in MHR’s remaining plays have been rising.


Source: Evaluate Energy – 2014 data not complete until April when all companies have reported 2014 budgets

Making any kind of growth had been difficult for MHR with these high costs to contend with across 4 plays (Eagle Ford average well cost in 2013 was $7.5 million) and non-core areas for a year following the fall in share price in 2012, which explains the market’s approval of a refocus in strategy as the company moves into 2014. Many companies have been undertaking a similar refocus in strategy due to high costs; the Bakken is one area in particular that saw many deals in 2013 with minor, non-core or non-operating acreage holders selling acreage positions to the more established companies in the play. Full analysis of the Bakken sales in 2013 can be found in the Evaluate Energy North American Oil & Gas Deals Report.

A Big Year Ahead

2014, if guidance figures eventually ring true, is set to be a spectacular year for MHR operationally. Its exit rate guidance for daily production is quite staggering at 35,000 boe/d considering production levels up to now.


Source: Evaluate Energy/MHR Guidance Press Release

The sale in Eagle Ford assets was the major contributing factor to a drop of around 5,000 barrels per day between Q2 and Q3 2013, but a robust capital expenditure plan for 2014 sees the exit rate shoot up to 35,000 boe/d. The company plans to spend $260 million in its Marcellus and Utica plays, and $50 million in the Bakken. The cautionary fact here is that this plan may increase the company’s gas weighting by the end of next year (already at 43% in Q4 2013) as the Marcellus and the Utica are both gas producing plays, but MHR is targeting liquids-rich areas in an attempt to avoid this.

Magnum Hunter Resources is a new addition to the Evaluate Energy database, which holds 20+ years of historic financial and operating data for over 300 oil and gas companies worldwide, and an extensive database focused on the US and Canadian shale gas & liquids industry, with company by company acreage holdings, capital expenditure budgets and planned well activity, as well as play by play average well costs. Evaluate Energy also provides oil and gas deals information with its M&A database.


Evaluate Energy’s Average Well Costs for US Shale plays are estimated by using company guidance figures for capital expenditures and planned drilling activity in each play. The figures are collected annually for the Bakken, Barnett, Eagle Ford, Fayetteville, Haynesville, Marcellus, Niobrara, Tuscaloosa Marine and Utica plays in the US, and for the Duvernay, Horn River and Montney plays in Canada, where figures are available. 2014 data will be complete by the end of April 2014.

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Ghana’s Jubilee Oil Field – Stable or Stagnating?

Posted by Mark Young

Feb 27, 2014 8:26:00 AM

In December 2010, the first oil was produced from Ghana’s Jubilee field, breaking a record for major deepwater development, as this was only 3.5 years after the field’s first discovery well. Tullow Oil (the unit operator – see note 1) led the celebrations, along with its major partners Kosmos Energy and Anadarko Petroleum, and the future for the field looked really bright. But although production now averages at around 100,000 barrels of oil equivalent per day (boe/d), issues are beginning to pile up and progress has been virtually non-existent since first oil. The field’s performance looks stable but may in fact be stagnating, according to this new analysis of annual 2013 data by Evaluate Energy, which holds financial and operating data for every publicly listed oil and gas company in Africa.

Kosmos Energy, the technical operator of the field (see note 2) and 24% owner, is probably the most exposed to the risk associated with the Jubilee field experiencing operational issues; Kosmos’ only producing asset is the Jubilee field. The company has just released its 2013 annual results and the operational data for Jubilee begins to highlight the problems.

Production has been relatively stable since a fall back to initial rates at the start of 2012, according to Kosmos’ quarterly data from Jubilee’s first oil.


Source: Evaluate Energy

The Jubilee partners noticed this fall in production and began what they called Jubilee Development Phase 1A, which involved drilling 5 new producing wells and 3 injection wells to bring production back up towards peak levels. Despite this, the producing facilities continued to experience technical issues into 2013, which caused unplanned downtime and a fall in production. Most of the companies’ efforts and cash have so far been spent on maintaining the field’s performance rather than improving it; reserves have also been stable since first oil.


Source: Evaluate Energy

Kosmos’ proved reserves data shows a steady increase in the developed percentage of total reserves and also shows that total reserves have not really changed in the 3 years of the field being operational. Proved reserves life at the current rate of production (97,500 boe/d was the average in 2013) without further development is now down to just over 6 years - at peak rate of 130,000 boe/d its even lower.

So the logical conclusion for the companies here is surely to invest heavily in development, try to unlock further reserves, enable an increase in production to raise more cash and then continue to reinvest. However, if the companies’ dealings with the Ghanaian government so far are anything to go by, this will prove to be much easier said than done. It is here where the main reason lies as to why this record breaking deepwater field has seemingly stagnated from the companies’ perspective since first oil.

The first step of investing heavily in development is being held back by the delay in finalising the Jubilee Full Field Development Plan (JFFDP) with the Ghanaian government, which is aimed at unlocking the full potential of the record breaking field. Kosmos states in its annual report that a plan was submitted to the government in December 2012. More plans are expected to be submitted in 2014, but Kosmos is quick to state that it can offer no assurances over approvals being received at all.

Even if the plans are approved quickly and the field is set for “full development”, there have also been delays with gas production facilities that mean production couldn’t be increased straight away anyway. A government project to build a pipeline and gas processing facility has fallen behind schedule, meaning the companies have no export plan for the associated gas being produced right now. Flaring would normally be an unhappy alternative here but the government has not granted the partners with a substantial-enough flaring license either, meaning any kind of immediate ramp-up in production due to the gas involved is impossible. The government is clearly paying a great deal of respect to making sure the oil is produced at a steady, manageable, and sustainable rate, but this is clearly at odds with how the companies actually doing the work want to move the project forward.

The current situation at the Jubilee field could be seen as stability or stagnation, depending on your own perspective. Either way, the situation is obviously not ideal for the operators and stands in stark contrast to the euphoria in 2010 upon first oil. If these governmental issues are not sorted, the situation will not end any time soon. The fact that even a record breaking mega project with such large potential is vulnerable to issues on this level is important to note. In particular, it should serve as a warning to companies and government bodies involved in the other African countries with major discoveries of their own, such as Kenya, Mozambique and Uganda. High resource figures and record breaking development timescales are obviously desirable, but the key for prolonged, successful oil and gas production seems to be a high level of cohesion between all relevant parties – and definitely a higher level of cohesion than is on show in Ghana right now.

This report was created using the Evaluate Energy database. Evaluate Energy provides efficient data solutions for oil and gas company analysis, with 20+ years of financial and operating data for the world’s biggest oil and gas companies, as well as every publicly listed company in Africa.

Now, All SEC-reported operational data, including oil and gas proved reserves, costs incurred and discounted future net cash flows, is now all available for Africa as a stand-alone region. For a demo of Evaluate Energy’s African Company database, click here.



1)        The Unit Operator is responsible for drilling and completing the development wells for the Jubilee Field development, according to the specifications outlined by the Integrated Project Team (IPT), and providing other in-country support. Upon first production, the Unit Operator assumed responsibility for the day-to-day operations and maintenance of the Floating production, storage and offloading vessel as well as overseeing and optimizing the reservoir management plan based on field performance, including any well workover activity or additional infill drilling and subsequent phases.

2)        The Technical Operator led the IPT, which consisted of geoscience, engineering, commercial, project services and operations disciplines from within the Jubilee Unit partnership. The technical operator evaluated the resource base and developed an optimized reservoir depletion plan. This plan included the design and placement of wells, and the selection of topside and subsea facilities. Responsibilities also extended to project management of the design and implementation of the complete field development system.

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East Africa Oil & Gas Outlook: Global Export Hub by 2020?

Posted by Mark Young

Feb 25, 2014 11:05:00 AM

East Africa could become the world’s next oil and gas export hub by 2020, according to a new report by Evaluate Energy. There are three countries with ambitions to make this a reality; Kenya, Mozambique and Tanzania. If even one of these countries achieves its goals, the impact on the global oil and gas industry would be very significant indeed.

The landscape of African oil and gas has changed very little in the last 20+ years. Historically, it has been the more economically developed Western and Northern countries that have produced the most oil and gas. Only Angola has stepped out of relative obscurity since 1990.


Source: Evaluate Energy

Angola has changed dramatically since 2000 and is the only country in the last 25 years to have increased production from under 500 bbl/d to rival the continents biggest 4 producing countries; Algeria, Nigeria, Libya and Egypt. Every other country in Africa produced 100,000 boe/d or less in 2012. African oil exports have therefore been restricted to coming from 4 of these 5 countries as well; Egypt is the only one of the big producers to import more oil than it exports. Angola is now the second largest oil exporter compared to its imports in the entire continent; Angola exports 1.7 million more barrels of oil than it imports each day. Angola also has a Liquefied Natural Gas (LNG) export terminal with a capacity to export 5.2 million tonnes of LNG per year (mtpa) that became operational in June 2013. Angola has shown just how quickly things can change with major investment into a developing country with large natural resources.

Recent developments in the exploration and production industry in 3 East African countries - Kenya, Mozambique and Tanzania - have laid a possible foundation for one or maybe some of these countries to follow in Angola’s footsteps on the path to exporting oil and gas on a major scale. This would end a 20+ year period of relative status-quo – Angola notwithstanding – on the continent. All 3 of these countries should be the main attraction of any new African investment before the end of the decade because of these export ambitions, which could represent a major opportunity for all E&P companies involved in the region, no matter their size.

These 3 export projects, which are the focus of Evaluate Energy’s new East Africa Oil & Gas Outlook report, make East Africa the continent’s region to watch for the remainder of the decade and the E&P companies involved very interesting prospects in the immediate future.

Overview of East African Export Ambitions:

Kenya The $25.5 Billion LAPSSET Project is underway, focused on exporting oil and gas from 3 countries out of Lamu Port on the northern coast.
Mozambique Multi-tcf deep-water gas discoveries by experienced IOC’s have been made and wealthy NOC benefactors mean that LNG exports are a real possibility in the very near future.
Tanzania Huge gas discoveries by IOC’s with LNG export ambitions and a separate Chinese-backed mega-port at Bagamoyo is planned.

Evaluate Energy’s East Africa Oil & Gas Outlook report is available now. Evaluate Energy provides efficient data solutions to oil and gas company analysis, with 20+ years of financial and operating data for the world’s biggest oil and gas companies, as well as every public company in Africa. Evaluate Energy also has a global oil and gas deals database, with every E&P deal worldwide since 2008, and a global assets database, with all major blocks and fields and also LNG import and export projects.

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Big Chinese Acquisitions and Anadarko’s Divestitures Continue in 2014

Posted by Mark Young

Feb 18, 2014 12:05:00 PM

Hong-Kong listed Brightoil Petroleum has made the ninth Chinese acquisition of over $1 billion since January 2013. The company has acquired Anadarko Petroleum’s (APC) non-operated interest in the Bohai Bay field, offshore China, via the US$1.075 billion purchase of Anadarko’s Chinese subsidiary.

The addition of approximately 11,000 boe/d is a big step for the Chinese company, which has seen losses in recent periods following difficulties in its oil trading business since the global financial crisis; Brightoil has posted net losses of around US$90-100 million in its last 2 financial reports in December 2012 and June 2013. Bolstering its E&P business with this Bohai Bay acquisition will increase the integrated nature of the company, and therefore create synergies for the company; the non-upstream segment will have greater access to company-produced oil and gas to help drive down costs. The deal has been received very well by shareholders following a short suspension in trading pending the acquisition announcement; on resumption of trading, Brightoil shares went up by 26.1%.

Brightoil Makes the Ninth +$1 billion Chinese E&P Acquisition Since January 2013

Below are the eight E&P deals by Chinese acquirers in 2013 that cost over US$1 billion. They were struck in regions all over the world and this deal by Brightoil is the first domestic acquisition of the collection.

2013 Deals by Chinese Companies for Over $1 Billion

Date Announced


Target Company


Brief Description

Total Acquisition Cost (US$000)


Sinochem Corporation

Pioneer Natural Resources

United States

Sinochem Corp farms into a 40% interest in 207,000 (82,800 net acres) in the Wolfcamp play from Pioneer Natural Resources.




Chesapeake Energy Corporation

United States

Sinopec acquires a 50% undivided interest in 850,000 of Chesapeake’s net oil and natural gas leasehold acres in the Mississippi Lime play in northern Oklahoma.






China National Petroleum Corporation (CNPC) acquires 28.57% (net 20% in Area 4) of Eni East Africa’s shares, owner of a 70% interest in Area 4, in Mozambique from ENI.




Marathon Oil


SSI Thirty-One Limited, a subsidiary of Sinopec acquires a 10% working interest in the Production Sharing Contract and Joint Operating Agreement in Block 31 offshore Angola from Marathon Internatinal Oil Angola Block 31 Limited.






CNPC acquires an 8.4% interest in the North Caspian Sea Production Sharing Agreement (Kashagan Field), Kazakhstan from Kazmunaigaz.






PetroChina acquires a 25% interest in the West Qurna-1 oilfield project in Iraq from ExxonMobil.

Undisclosed Assumed over $1 billion



Apache Corporation


Sinopec International Petroleum Exploration and Production Corporation, a fully-owned subsidiary of Sinopec Group acquires a 33% minority participation in Apache's Egypt oil and gas business.






CNPC E&D Holdings Cooperatief U.A. and CNODC International Holding Ltd. an indirect subsidiaries of PetroChina acquires Petrobras Energia Peru S.A.


Source: Evaluate Energy M&A Database. Note: This table does not include CNPC and CNOOC signing an approximate $620 million deal each to participate in the pre-salt Libra consortium in Brazil, or Sinochem's terminated agreement with Petrobras to acquire its interest in the Brazilian Parque das Concha block for $1.54 billion.

Full Analysis of China’s huge acquisitions in 2013 - including deal-specific metrics and rationales - is available in Evaluate Energy’s new M&A Report for 2013.

Anadarko’s Divestitures

From Anadarko’s point of view, this was the company’s fourth divestiture for over $500 million since January 2013. 

Sales by Anadarko Petroleum in 2013

Date Announced


Target Company


Brief Description

Total Acquisition Cost (US$000)



Anadarko Petroleum Corp.

United States

Anadarko Petroleum Corporation farms out a 12.75% working interest in its Heidelberg development project located in the deepwater Gulf of Mexico




Anadarko Petroleum Corp.


ONGC Videsh Ltd., a wholly owned subsidiary of ONGC acquires a 10% interest in Mozambique's Offshore Area 1, Rovuma Basin from Anadarko Petroleum Corporation



Vanguard Natural Resources

Anadarko Petroleum Corp.

United States

Vanguard Natural Resources, LLC acquires natural gas and oil properties in the Pinedale and Jonah fields of Southwestern Wyoming from Anadarko E&P Onshore LLC


Source: Evaluate Energy M&A Database

This is another hefty sum received for assets the company has deemed non-core to its operational plans, something the company itself terms “accelerating value”. Anadarko has made US$13.5 billion-worth of asset or business unit sales with an announced value since 2007 - its latest presentation says the overall total is over US$16 billion, including deals for undisclosed amounts. These deals have strengthened the company’s balance sheet and have made essential funds available for Anadarko’s many major projects both at home and around the world.

One of these major projects is in Mozambique, where the company is leading the development of a Liquefied Natural Gas exporting terminal with 50 million tonnes per year of capacity. In 2013, Anadarko agreed to lower its interest by 10% in the project with a sale to India’s ONGC. The deal simultaneously reduced Anadarko’s exposure to the risks associated with a sure-to-be expensive deep-water gas production and export project, secured extra funding for the project and strengthened the company’s ties with a potential gas trading partner. This was just one of many significant deals to occur in Mozambique last year; further analysis of these deals is available in Evaluate Energy’s new M&A Report for 2013.


Evaluate Energy provides efficient data solutions for oil and gas company analysis with 20+ years of historical financial and operating data for the world's biggest and most exciting oil and gas companies. Clients also receive access to our M&A database, which covers every E&P deal worldwide back to 2008.


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Rosneft: The World's Newest Oil & Gas Super Major

Posted by Mark Young

Feb 6, 2014 12:15:00 PM

Russia’s Rosneft made some huge acquisitions in 2013 and these acquisitions have propelled the company into a position where its E&P segment now produces more oil and gas per day than ExxonMobil and Royal Dutch Shell, according to analysis of the Russian company's annual 2013 data by Evaluate Energy.


Source: Evaluate Energy - BP-owned portion of Rosneft (19.75%) excluded from 2013 BP production figures to avoid data duplication

In 2012, Rosneft’s daily average production was around 2,700,000 boe/d, an amount which ranked the company on a par with the likes of Chevron, Petrobras, Total and fellow Russian, Lukoil. All four of these are undoubtedly major oil and gas players, but these companies all produced over 35% less than ExxonMobil did in 2012. Rosneft has recently released its annual results for this year, and the change year-on-year is colossal; Rosneft’s production has increased by 78% in just one year to 4,800,000 boe/d, over 600,000 boe/d more than ExxonMobil reported in its own annual results.

The main driver of this production growth was clearly the $57 billion acquisition of TNK-BP that closed in March 2013, but the company also announced many other deals in 2013; one major example being the $2.9 billion acquisition of a 49% stake in ITERA Oil & Gas, which added around 103,000 boe/d of production to Rosneft’s totals.

Rosneft features heavily in Evaluate Energy's New Global Oil & Gas Deals Review 2013, which is available to buy here.

The acquisitions have had a significant financial impact on the company’s E&P sector too, as Rosneft has maintained its approximate 90% oil weighting of production in its E&P segment from 2012 to 2013. In fact, Rosneft benefits from the highest oil weighting percentage of all of the major companies included in the production graph above.


Source: Evaluate Energy - Ranked on 2013 Annual Oil & Gas Production (000 boe/d), 9M figures used if annual production yet to be reported

This maintaining of a 90% oil weighting has caused an even sharper increase in gross revenues [1] for the E&P sector than a similar increase in production would have caused for the other companies in the graph, as oil is priced so much higher than gas. Q4 2013 revenues (712 billion Rubles) from the E&P sector are 88% higher than they were in Q1 2012, and 72% higher than Q1 2013.


Source: Evaluate Energy

Rosneft’s refinery sector has also seen a boost following the TNK-BP acquisition, with gross revenues increasing here by 62% since Q1 2013 to 620 billion Rubles in Q4 2013. The operational increases in the refinery sector following 2013’s acquisitions are also very significant, albeit not as spectacular as the E&P production levels leapfrogging ExxonMobil.


Source: Evaluate Energy

Clearly, the company is now also ranking amongst the world’s heavyweights when it comes to putting feedstock through its refineries. A year ago, Rosneft was the lowest company in this group by some distance in terms of its refinery throughput, but 2013’s 47% increase to 1,850,000 bbl/d has shifted Rosneft significantly higher. Overall, Rosneft’s net income rose 51% year-on-year to 551 billion Rubles from 365 billion Rubles in 2012.

Rosneft’s market cap (US$81 Billion) and gross enterprise value (US$155 billion) [2] are still a long way below those of ExxonMobil and Royal Dutch Shell, for example, but the company is now undoubtedly operating on a level that means Rosneft must be part of any future discussion about the world’s biggest oil and gas companies.

This report was created using the Evaluate Energy database. Evaluate Energy provides efficient data solutions for oil and gas company analysis, with 20+ years of financial and operating data for the world's biggest oil and gas companies, as well as extensive M&A & Assets datasets.

[1] Gross Revenues are revenues before the deduction of excise taxes/royalties.
[2] Gross Enterprise Value is calculated as the market value of gross debt, plus ordinary and preference shares outstanding. Market value of debt and preference shares is assumed to be equal to period-end values in balance sheet.
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Shell's Profit Warning a Symptom of Wider Trend Among the Majors

Posted by Richard Krijgsman

Jan 27, 2014 9:22:00 AM

Shell's fourth Quarter Profit warning was an unwelcome surprise to investors and probably reflects a less than robust approach to investor relations compared to its peers. However, the underlying reasons for the company's weaker-than-expected performance apply equally to the other Majors and Shell is not alone in suffering from a combination of market factors that have been undermining its ability to grow profitably. That's according to an Evaluate Energy analysis and overview of the key factors affecting all the Major companies.

First of all, free cash flow is being squeezed. Not just for Shell but for all the other Majors as well. Free cash flow is defined as net cash available to equity and debt holders after providing for operations and capital expenditure. It is calculated as operating cash flow after cash taxes but before interest and dividend payments, less capital expenditure.


The two main reasons for this are, first that Capital spending has been rising on the back of burgeoning development costs as the Majors rush to replace their huge reserves....


...and second, operating costs are rising steadily (cost figures below are shown as negatives).....


...while at the same time, revenues are flat or falling 


The response of the Majors appears to be to sell assets and trim future capex plans - Total recently announced 2013 capex had peaked, while Shell and BP are selling assets and cancelling projects. The consequences of that approach will certainly help cash flow performance, but reserve replacement rates, and with it production capacity, will eventually start to fall. Meanwhile development costs - albeit possibly slowing down in their rate of growth - will remain high. 

Evaluate Energy provides upstream benchmarking solutions for oil and gas companies, with 25+ years of financial and operating company data, an extensive global assets database nad established industry expertise. 

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