EIA: Debt Service Uses a Rising Share of U.S. Oil Producers’ Operating Cash Flow

Posted by Mark Young

Sep 18, 2015 9:30:33 AM

Latest analysis of Evaluate Energy data by the U.S. Energy Information Administration reveals that U.S. onshore oil companies had to lean more on their operating cash flow to service their debt in Q2 2015 than at any time in the previous 13 quarters.


Read the Full EIA Study Here

The article from the EIA states that because low oil prices have significantly impacted cash flow for U.S. oil producers and that companies have had to adjust to this by reducing capex spends and raising cash via debt and equity financing arrangements. Because of this, large amounts of debt have now been accumulated and now, in Q2 2015, servicing this debt is using a higher portion of operating cash flow for U.S. onshore producers than in previous periods. 

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EIA: U.S. onshore producers face challenging times

Evaluate Energy: More Gloom on the Horizon for Bakken Companies in Q3 2015

This study from the EIA was completed using data from the Evaluate Energy database. Evaluate Energy provides clients with efficient data solutions for oil and gas company analysis. This includes over 25 years of financial and operating data for the world’s biggest and most significant oil and gas companies, M&A deals, a global E&P assets and LNG database and an emerging product that focuses on the North American shale industry.

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Company Spotlight: Kelt Exploration Ltd. Builds Solid Asset Base

Posted by Mark Young

Sep 17, 2015 10:11:00 AM

In October 2012, Kelt Exploration Ltd. was formed in a spin-off after ExxonMobil acquired Celtic Exploration Ltd. Its growth in production since that time has been impressive. The operational base is now very robust, but Q2 2015 results do highlight an increase in operational expenses caused by the growth strategy based around acquisitions employed by Kelt since the start of 2014.

Overview of Kelt’s Growth Since Start of Operations


Source: CanOils

This is undoubtedly steady, aggressive growth. The company has been consistently moving up in the rankings of production by Canadian companies. In CanOils’ latest Top 100 Oil & Gas Companies report, the company is the 34th highest producing TSX listed company in Q2 and the 30th highest TSX producer with assets in Canada. 

The main strategy for the growth has been acquisitions and as of July 2015 – according to CanOils Assets data – the company was participating in 1,246 active wells across Alberta and British Columbia. 

Kelt Exploration Ltd. – Active Wells as of July 31, 2015 (1,246 wells)


Source: CanOils Assets Webmap - Click here for Map Legend

Analysis using data from the CanOils M&A database reveals that Kelt has completed a grand total of approximately $710 million worth of acquisitions since the start of 2013, which is composed of 43% cash, 39% stock and 18% debt assumption. In this time, Kelt has acquired two companies – Capio Exploration Ltd. in July 2014 and Artek Exploration Ltd. in April 2015. It also completed a major asset acquisition from Penn West Petroleum Ltd. in December 2013 to establish one of its core areas. So far in 2015, besides the Artek deal, the company has completed two other minor deals for a total of around $15 million (the company acquired assets from TAQA and Enerplus Corp; see note 1.)

The three deals in 2015 were chiefly targeted at giving Kelt a more consolidated ownership position over its core properties and surrounding infrastructure. Analysis of data from CanOils Assets shows that acquiring Artek, for example, involved interests in 313 oil and gas wells that were still listed as active in July 2015 – Kelt already had an interest in 181 (58%) of these wells prior to the acquisition (see note 2). The acquisition was completed at a very reasonable cost as well, with normalised consideration per boe of $32,810 for production and $7.37 for proved reserves (see note 3).

Following these recent deals, according to Kelt’s August 2015 corporate presentation, the company’s average working interest of its developed properties is 58% and for its undeveloped acreage the average working interest is 82%. So the acquisitions have increased the ownership over its current production and as more and more of its undeveloped properties are brought onstream, this ownership level and therefore control over its own production will rise. The deals have also increased the company’s oil weighting to give Kelt a more balanced portfolio to work with. The company’s production in Q2 2015 was 36% oil, a significant increase from Q1 2014’s 30%.

The moves to consolidate ownership in wells and infrastructure in key producing areas as well as the move to a more balanced oil-to-gas portfolio would normally make a lot of sense. The company will be more in control of its own destiny while also enjoying more flexibility to cope with negative price movements in either oil or gas.

Operating Expenses per Barrel

However, the speed of this consolidation and movement to a balanced portfolio has caused operating expenses per barrel to increase very quickly. While commodity prices remain low, these expenses are vital to keep under control. Below is a chart of the Q2 2015 operating expenses per barrel for Kelt and eight other Canadian companies that produce between 10,000-50,000 boe/d with an oil weighting of between 25%-50% (Kelt’s oil weighting in Q2 2015 was 36%). The nine companies ranked between 22nd and 54th in the most recent CanOils’ Top 100 Oil & Gas Companies report (see note 4).


Source: CanOils

Kelt recorded the highest operating expense per barrel of this peer group at $13.58. Kelt lists three reasons in its quarterly report for the high costs:

  • Movement towards oil weighted assets
  • Third party downtime reducing production by 1,630 boe/d
  • “Initial integration” of Artek properties

The first two reasons will obviously have contributed to the number being higher than in the past for Kelt itself, but neither can be the main reason for the company operating at much higher costs than its peers. Firstly, the other companies in the peer group all have an oil weighting similar to Kelt’s current portfolio, so this cannot be the main reason for Kelt's higher operating expenses per boe produced. Secondly, if the third party downtime did not happen and the 1,630 boe/d of production was not lost, Kelt’s operating expense per barrel would still have been second highest of the peer group at $12.53. Location of assets could, of course, play a part here as some of the eight companies operate in completely different areas to Kelt, but as Paramount Resources Ltd., for example, has a large asset base in and around Kelt’s operations with a similar overall production mix (40% oil in Q2 2015) and enjoys much lower costs, again this cannot be a hugely significant factor.

Therefore, it must be the integration of the Artek assets and the other properties acquired to sharply increase production levels over the past 18 months that contribute to the company’s high expenses. The use of the phrase “initial integration” and further notes in the company’s quarterly report suggest that Kelt management is viewing these high costs as a temporary issue. In low price environments, keeping operating expenses under control is essential for achieving and maintaining any sort of profit. Kelt shareholders will no doubt be hoping that the company’s high operating expenses are indeed as temporary as company rhetoric suggests, so that Kelt can actually succeed with this strong base of operations it has quickly put together since formation.

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1) The selling companies for both of these deals were deduced from CanOils Assets data and not reported by Kelt itself.

2) The figures here only include oil and gas wells. The acquisition of Artek also involved 18 wells that were not oil and gas wells, but instead were disposal, drainage or injection wells. Kelt only had an interest in 1 of these 18 wells prior to acquiring Artek, a water disposal well.

3) Normalised deal metrics for production and proved reserves are calculated for all relevant deals in the CanOils M&A database. To calculate these metrics, CanOils will remove the estimated value of any probable, possible, contingent and prospective resources, as well as any values of undeveloped land, large tax pools and non-E&P assets involved in the deal, from the total acquisition cost before calculating the amount that companies are paying per barrel for production and proved reserves in a transaction.

4) PrairieSky Royalty Ltd. (TSX:PSK) was the only company in CanOils’ Top 100 Oil & Gas Companies report for Q2 2015 that fits the criteria for the chart that was not included. As a company that holds royalty interests only, it does not report operating expenses in the same way that the other companies do. With 17,205 boe/d, PrairieSky was the 39th biggest producer on the TSX for Q2 2015.

5) All $ values refer to Canadian Dollars.


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The Top 100 Canadian Oil & Gas Companies

Posted by Mark Young

Sep 15, 2015 5:41:00 AM

CanOils is pleased to announce the release of its new report, Canada's Top 100 Oil & Gas Companies, which has been compiled using Q2 2015 Canadian oil & gas production results from all TSX and TSX-V listed Canadian oil and gas companies in the CanOils database.

Canadian M&A Activity Has Huge Impact on Rankings

The quarter saw many acquisitions take place that had major impacts on the Top 100 rankings. The most significant deal was the acquisition of Q1 2015’s 4th biggest TSX company, Talisman Energy Inc., by Spain’s Repsol. This meant that Talisman was no longer in the rankings and a very high number of companies (65 out of this quarter’s 100) were sitting in a higher position in the Top 100 than in Q1. Similar impacts, albeit to a lesser extent, were made by Tourmaline Oil Corp.’s acquisition of Mapan Energy Ltd., Aspenleaf Energy Ltd.’s acquisition of Arcan Resources and, of course, by Crescent Point Energy Corp.’s acquisition of Legacy Oil + Gas Inc..

There were many companies out of the 65 who climbed the rankings this quarter that would have climbed regardless of the above acquisitions removing significant companies from positions above them. Kelt Exploration Ltd.’s own M&A activity, for instance, saw the company climb 10 places in the rankings. The company announced the acquisition of Artek Exploration Ltd. in 2014 and this closed in April, and saw a 22% increase in Q2 2015 production compared to Q1 as a result. Freehold Royalties Ltd. also climbed the rankings after an acquisition of two royalty packages from Penn West Petroleum Ltd. in the Viking Light Oil region of Saskatchewan. Many companies also fell in the rankings due to asset sales, full details of which are available in the Top 100 Oil & Gas Companies report.

Maintenance, Turnaround Work and Disruptions Cause Many Companies to Fall

Maintenance and production curtailments due to disruptions were the other major influencing factors on this quarter’s rankings. Within the Top 20, Canadian Oil Sands Ltd. and MEG Energy Inc. both saw their oilsands outputs limited in Q2 following planned turnaround work at their respective Syncrude and Christina Lake projects. In MEG’s case, the related drop in production was bigger than originally expected. Forest fires in Alberta meant that the planned turnaround at Christina Lake could not be completed on schedule. The company eventually posted Q2 production levels 11,000 barrels per day less than Q1. Maintenance periods and unreliability issues impacted many companies throughout the Top 100 ranking.

Overall Statistics

For the second quarter in a row, UK North Sea-focused Iona Energy Inc. was amongst the biggest climbers, whilst Mart Resources Inc. continued to experience issues with its production and midstream infrastructure in Nigeria, causing the company to again rank amongst the biggest fallers. Granite Oil Corp., the formation of which is extensively looked at in the report with the help of data from CanOils Assets, was the quarter’s biggest faller. The company was formerly known as Deethree Exploration Ltd. and lost a significant portion of its production in May when the company was split into two. Boulder Energy Ltd. is the new company that was formed in this reorganisation. 

TOP100_June_2015_Blog_TableSource: CanOils via Canada's Top 100 Oil & Gas Companies, June 2015

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


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



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More Gloom on the Horizon for Bakken Companies in Q3 2015

Posted by Mark Young

Sep 3, 2015 6:17:00 AM

As commodity prices fell at the end of 2014 and in early 2015, companies that participate in the Bakken shale in North Dakota and Montana were hit the hardest amongst U.S. unconventional operators. The WTI oil benchmark price dropped to below $50 in the first quarter of 2015 and the Bakken companies suffered the biggest drops in netbacks on average than any other major play or producing area. A brief respite was experienced as WTI prices rebounded to an average closer to $60 in Q2, but as of August 25, 2015, the Q3 average WTI price had fallen again, sitting below even the Q1 average. Using Evaluate Energy data from the past 12 months, we can see that Q3 netbacks for Bakken operators should therefore be low again, despite widespread improvements in operational costs per barrel of oil produced.

Average WTI Prices per Quarter


Bakken Netbacks Tumble in Q1 2015

In a study of 80 U.S. based companies’ pre-hedging operating netbacks (see note 1) for the periods Q3 2014 and Q1 2015, the data shows that the companies in the Bakken suffered the most with the fall in commodity prices.

Twelve of the 80 companies have at least a significant portion of their upstream operations located in the Bakken area – Abraxas Petroleum Corp. (AXAS), Continental Resources Inc. (CLR), Emerald Oil Inc. (EOX), Halcón Resources Corp. (HK), Hess Corp. (HES), Linn Energy LLC (LINE), MDU Resources Group Inc. (MDU), Northern Oil & Gas Inc. (NOG), Oasis Petroleum Inc. (OAS), QEP Resources Inc. (QEP), Triangle Petroleum Corp. (TPLM) and Whiting Petroleum Corp. (WLL).

These companies’ percentage drops in operating netback between Q3 2014 and Q1 2015 has been plotted on the following chart with the percentage drop experienced by every other company in the group of 80, which includes international and multinational operators, Eagle Ford operators, Marcellus operators and Permian Basin operators (see note 2).

Download Supplemental Data Booklet for this article.


Source: Evaluate Energy – For a larger image, download the Supplemental Data Booklet for this article here

Every one of the 80 companies saw its operating netback fall between Q3 2014 and Q1 2015, but on average it is the companies in the Bakken that saw the biggest fall. This was probably to be expected due to the focus on oil production in the Bakken versus output of gas (Marcellus) or gas liquids (Eagle Ford) in some of the other play areas. A dramatic drop in oil price was always going to impact Bakken operators to a greater extent than some of their peers. However, the effect of the falling prices on Bakken operators does still stand out. For more on falling netbacks between Q3 2014 and Q1 2015, download the supplemental data booklet for this article.

Some Respite in Q2

As WTI rebounded somewhat towards an average of almost $60 in the second quarter of 2015, the Bakken companies saw their netbacks rebound in turn. 


Source: Evaluate Energy – MDU and TPLM are not included (see note 3).

Whilst Q2 must have been encouraging for the companies in question, there is a definite pattern here and this will be concerning heading into Q3. Of course, in terms of the actual prices and netbacks achieved, some companies have done better than others, but wide swings in oil prices seem to have affected the Bakken companies’ netbacks as one, not as individual entities, over the past 12 months. So it is reasonable to assume that Q3’s decline in WTI to another quarterly average of under $50 is likely to continue this pattern and significantly impact all Bakken-focused companies in a negative manner.

Costs Being Brought Under Control

On the whole, however, it looks as if the Bakken companies are in a better place to deal with falling prices in Q3 than they were in Q1. The Bakken company netbacks are looking like they will not fall to Q1 levels if the WTI price for the whole of Q3 ends up averaging at the same price as Q1 ($48.57). This is due to operating expenses per barrel being lower – on average – across the group in Q2 2015 than the previous three quarters, particularly Q1.


Source: Evaluate Energy – MDU and TPLM are not included again (see note 3)

Only Abraxas (due to lower production) and Emerald Oil (due to issues with maintenance, water disposal and regulatory expense increases) saw an increase in their operating expenses per barrel, whilst the other Bakken companies all reduced their expenses per barrel compared with Q1.

So whilst Q3 is looking like another gloomy period for company netbacks in the Bakken with a resumption in lower commodity prices, it is likely not to be as bad as Q1 – but only if each company can continue to keep its operating expenses under control as we have seen in Q2.

All data here is taken from the Evaluate Energy database, which provides Evaluate Energy subscribers with over 25 years' coverage of the world's biggest and most significant oil and gas companies. Evaluate Energy also has a mergers & acquisitions database, covering all E&P asset, corporate and farm-in deals back to 2008, as well as refinery, LNG, midstream and oil service sector deals. For more on Evaluate Energy and its products, please download our brochure.

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1) Pre-hedging operating netback is calculated by taking each company’s E&P revenue, E&P operating costs and transportation expenses and bringing them to a per boe produced level. This calculation excludes any realised hedging gains.

2) The group of 80 companies included in the Q3 2014 – Q1 2015 report is available in the supplemental data booklet to this article – click here to download.

3) MDU has started to treats its upstream segment as discontinued operations as it attempts to sell its E&P subsidiary Fidelity Exploration & Production and does not report E&P figures anymore, whilst TPLM has not yet reported (as of time of writing) its results for the second quarter because the company’s year end is January, rather than December; the company’s Q2 results are due to be released in the second week of September.

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How Did the Oil & Gas Majors Perform in Early 2015?

Posted by Mark Young

Aug 18, 2015 5:05:04 AM

As Q2 results continue to flood in, Evaluate Energy has reviewed the performance of the world’s oil and gas majors – BP, Chevron, ConocoPhillips, ExxonMobil, Royal Dutch Shell and Total – to gauge the impact of the price collapse of late 2014  on their respective starts to 2015, with the main focus on their upstream earnings, production and capital expenditures.

Earnings Down, Production Slightly Up

Predictably, in terms of unadjusted earnings (see note 1) in the upstream sector, the start to 2015 has not been the six month period the majors will have hoped for. The fall in prices saw all six companies report lower quarterly earnings in Q1 and Q2 than their respective average quarterly earnings from 2014, with half of the group recording upstream losses in Q2; BP’s Q2 earnings were impacted by a loss of over $10 billion related to the Gulf of Mexico spill response, whilst Chevron – remarkably recording its first unadjusted upstream quarterly loss in since Q4 2001 – and ConocoPhillips both suffered impairment charges to account for their own upstream losses in Q2.

Production was a different story, however, with all companies apart from Shell averaging a slightly higher rate over the first six months of 2015 compared with the full year 2014.


All companies did record a slightly lower average production rate in Q2 2015 compared to Q1 2015, but, with Shell’s acquisition of BG in the pipeline, all the majors are looking at the prospect of higher production than they had in 2014 as we enter the latter half of the year.

Capital Expenditure Cuts

E&P capital expenditure budgets were the first thing that many companies adjusted when faced with the prospect of prolonged lower commodity prices – but the majors did not cut as drastically as everybody else.

In a quick study of 60 U.S. listed companies (see note 2) that cut upstream capex spends in Q1 2015 compared with the average spend per quarter in 2014, the average cut was around 33%, with some companies slashing upstream capex by nearly 80% compared to last year’s average quarterly spend. In contrast, Total bucked the trend and spent more in Q1 compared to 2014’s quarterly average, whilst the other 5 majors average only a 20% cut between them. Moving into Q2, 53 of the 60 U.S. companies continued to drop capex spends from Q1 levels at an average of 32%. As for the majors, ConocoPhillips – the only company of the 6 not to have a refining sector to bolster its overall earnings by taking advantage of lower raw material costs – was the only one that continued to significantly drop its spending, whilst BP, Chevron, ExxonMobil and Shell all maintained Q1 levels and Total dropped spending from its high Q1 outlay. For Total, this means its 2015 average quarterly spend is now back in line with average 2014 levels. 


Of course, it’s not easy to pull the plug on large-scale projects, which tend to be the domain of the majors, and capital will be committed to them regardless of price movement. While this dynamic will have played some role in the majors not cutting their spending as much as smaller companies, the apparent lack in reaction by the majors compared to the rest of the industry does stand out.

However, should commodity prices continue to drop or fail to rebound any time soon, it wouldn’t be the greatest of surprises to eventually see the majors cut their spending more deeply.

All data here is taken from the Evaluate Energy database, which provides Evaluate Energy subscribers with over 25 years' coverage of the world's biggest and most significant oil and gas companies. Evaluate Energy also has a mergers & acquisitions database, covering all E&P asset, corporate and farm-in deals back to 2008, as well as refinery, LNG, midstream and oil service sector deals. For more on Evaluate Energy and its products, please download our brochure.

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1) The term “unadjusted earnings” used throughout refers to income including the impact of non-recurring items, such as impairments, legal or restructuring charges, as well as gains or losses on asset sales. Apart from BP, all majors report this item for the upstream segment on a post-tax basis. BP reports this item on a pre-tax basis.

2) The 60 U.S. listed companies that dropped capex in Q1 2015 compared to average 2014: Abraxas Petroleum Corp., Anadarko Petroleum Corp., Antero Resources Corp., Apache Corp., Approach Resources Inc., Atlas Resource Partners L.P., Bill Barrett Corp., Bonanza Creek Energy Inc., Breitburn Energy Partners L.P., Cabot Oil & Gas Corp., California Resources Corp., Callon Petroleum Co., Carrizo Oil & Gas Inc., Chesapeake Energy Corp., Cimarex Energy Co., Clayton Williams Energy Inc., Comstock Resources Inc., CONSOL Energy Inc., Denbury Resources Inc., Devon Energy Corp., Diamondback Energy Inc., Emerald Oil Inc., Enerplus Corp., EOG Resources Inc., EP Energy Corp., EV Energy Partners L.P., Freeport-McMoRan Inc., Goodrich Petroleum Corp., Gulfport Energy Corp., Halcon Resources Corp., Hess Corp., Laredo Petroleum Inc., Linn Energy LLC., LRR Energy L.P., Marathon Oil Corp., Matador Resources Co., Memorial Production Partners L.P., Murphy Oil Corp., Noble Energy Inc., Northern Oil & Gas Inc., Oasis Petroleum Inc., Parsley Energy Inc., Penn Virginia Corp., PetroQuest Energy Inc., Pioneer Natural Resources Co., QEP Resources Inc., Rex Energy Corp., Rice Energy Inc., Rosetta Resources Inc., RSP Permian Inc., Sanchez Energy Corp., SandRidge Energy Inc., SM Energy Co., Southwestern Energy Co., Stone Energy Corp., Swift Energy Co., Ultra Petroleum Corp., Unit Corp., W & T Offshore Inc., Warren Resources Inc.

3) Upstream capex in this study excludes the impact of any asset dispositions.

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Do You Spend Hours Downloading Oil and Gas Company Reports?

Posted by Mark Young

Jul 15, 2015 7:09:00 AM

1000s of Canadian Oil & Gas Company Reports at Your Fingertips

As part of CanOils’ continued lead in oil and gas company financial and operating analysis solutions, we are pleased to announce an upgrade that adds Canadian company quarterly, annual and reserve reports to our Documents product, a simple web-based platform that CanOils subscribers can use to download all the reports they need in a matter of minutes.

Find out more by requesting a demo of CanOils Documents here.

The Upgraded Service

In addition to the 1000s of corporate presentations that CanOils has collected, stored and made available since 2008, we have now added 1000s of new reports to our offering.   

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These have been cleaned, catalogued and backdated for all TSX and TSX-V listed companies in the CanOils coverage portfolio and all future reports will be available within 1 working day of release.

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Get in Touch

If you would like further information on either the CanOils Documents product or the automation service, or if you would simply like one of our support team to walk you through the product, simply contact your local representative on the number below or complete a demo request here and we'll take care of the rest.

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Canadian Oil & Gas Companies Raise More Funds in H1 2015 than H2 2014

Posted by Nikki Zenonos

Jul 3, 2015 12:22:00 PM

Deal Values Recover After a Lacklustre End to 2014, But Deal Count Falls

A total of $10.5 billion was raised by publicly-quoted upstream Canadian oil and gas companies during the first half of 2015, a significant rebound from a low $8.2 billion total in the second half of 2014 and almost in line with the $11.4 billion total in the first half of 2014 - suggesting that the global price crash had little sustained impact on the bigger Canadian companies' ability to raise funds. However, according to new analysis by CanOils, even though total deal value increased in the six month period, the number of deals – 108 deals were completed in H1 2015 by TSX and TSX-V listed companies – actually represents a 33% reduction compared to H1 2014. CanOils tracks all equity and debt financings raised by TSX and TSX-V companies. 


Source: CanOils Financings Database

TSX Companies Have Easy Access to Capital

The effect of the crash in oil price at the end of 2014 seemed to be short-lived for TSX-listed companies in terms of access to capital markets, with $10 billion raised during H1 2015. This is back up at H1 2014 levels and much higher than was seen at the end of 2014 as commodity prices began to tumble. $7 billion of this total was raised in equity and the other $3 billion in debt, compared with an equal split of $10 billion in equity and debt during H1 2014. 


Source: CanOils Financings Database

TSX Companies – Equity Deals

The largest single equity issue recorded in the first six months of 2015 was the $1.50 billion raised by Cenovus Energy Inc. (TSX:CVE), the net proceeds of which were used to partially fund the company’s $1.8-$2.0 billion capital expenditure program for 2015 as well as to repay commercial paper outstanding as it matures and for general corporate purposes. The pricing of $22.55 per share was at a discount of almost 10% to the 20-day volume weighted trading average price (VWAP). This deal was followed closely by the second largest deal where $1.44 billion was raised by Encana Corporation (TSX:ECA) to redeem its US$700 million of long-term debt maturing in 2017 and C$750 million of long-term debt maturing in 2018 on April 6, 2015. At $14.60 per share, this was a 13% discount to the VWAP. Both offerings were filed under prospectus supplements and brokered by a syndicate of underwriters; RBC Capital Markets was one of the lead underwriters for both deals.


TSX Companies – Debt Deals

Husky Energy Inc. (TSX:HSE) completed the largest debt issuance in H1 2015, raising $750 million through the issuance of non-convertible notes with a coupon rate of 3.55% per annum, due to mature in 2025. The net proceeds of the offering were intended to be used for the partial repayment of short term debt incurred in connection with its U.S. refining operations. Other notable TSX company debt offerings during the period were the US$450m of 6.875% senior unsecured notes due 2023 raised by Paramount Resources Ltd. (TSX:POU), US$425m of 6.75% senior notes due 2023 raised by Seven Generations Energy Ltd. (TSX:VII) by way of a private placement and C$500 million of 2.89% medium-term series 2 notes due 2020 raised by Canada’s largest producer, Canadian Natural Resources Limited (TSX:CNQ). 


TSX-V Companies Continue to Feel the Squeeze

TSX-V financings accounted for $330m raised in the first six months of 2015, down 75% year-on-year, with equity raisings contributing $230 million (down 76%) and debt financings a further $100 million (down 72%) during H1 2015. However, deal count was down just 41%, which indicates slightly larger deals were completed in this six month period on average.


Source: CanOils Financings Database

TSX-V Companies – Equity Deals

A combination of subscription receipts, common shares and flow-through shares (CDE) were issued by Tamarack Valley Energy Ltd. (TSX-V:TVE) in June 2015 to complete the largest equity financing by a TSX-V listed company in H1 2015 for $84 million. The financing was carried out by a syndicate of underwriters co-led by National Bank Financial Inc. and Dundee Securities Ltd. at a discount of 13% to the 20-day VWAP for the subscription receipts and common shares and was over-subscribed, raising $14m pursuant to an over-allotment option. The net proceeds of the Subscription Receipts would fund the acquisition of certain assets in the Wilson Creek area of Alberta which in aggregate are expected to add approximately 1,450 boe/d (45% light oil and NGLs) as of the closing date and includes 128 (88 net) total sections of land in the greater Wilson Creek/Alder Flats areaSee Evaluate Energy’s review of Q2 2015 M&A activity here. Net proceeds of the Offered Shares are expected to be used to expand the Company's 2015 capital expenditure program, whilst the proceeds from the concurrent private placement of CDE Flow-Through Shares will be used to incur and renounce Canadian development expenditures. CanOils Assets is a powerful new tool that can help you analyse assets for sale in Western Canada.


TSX-V Companies – Debt Deals

Rooster Energy Ltd. (TSX-V:COQ) was involved in the largest single issuance of debt during H1 2015 of all TSX-V listed companies, raising US$60 million in senior secured notes, due to mature in 2018, for the repayment of existing senior secured debt in the principal amount of US$45 million, plus accrued interest and closing costs as well as to fund the company's development drilling program and other general corporate purposes.



1) All dollar amounts are in Canadian dollars unless otherwise expressly reported.

2) All data here is sourced from CanOils financing database, which tracks all equity and debt financings raised by TSX and TSX-V companies in an easy-to-use database. Clients have access to all deal metrics mentioned above, as well as underwriters’ information related to fees and participation and much more.


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Q2 2015 Oil & Gas M&A Recovers to $115 billion in E&P Sector

Posted by Eoin Coyne

Jul 2, 2015 12:14:00 PM

Large Headline Figure Conceals Enduring Caution in the Market

The total value of upstream oil and gas deals reached $115 billion during Q2 2015 ranking it as the second largest quarterly value since Evaluate Energy initiated its oil and gas M&A coverage 7 years ago. Although the headline figure falls just $13 billion short of the $128 billion value of deals in Q4 2012, the real sentiment of the quarter has been masked by the $84 billion (including debt) acquisition of BG by Royal Dutch Shell.

Without the support of the Shell-BG deal the quarterly total value of deals would have stood at $31 billion, which although is more than double the value during Q1 2015, is still a value that suggests that the market is still showing a large degree of caution in regards to its perception of where the price of oil is going to go in the near future. A better gauge of the underlying activity can perhaps be seen in the number of upstream deals with values greater than $100 million and $50 million. Analysis using Evaluate Energy’s M&A Deal Analytics tool reveals that Q2 2015 is still lagging far behind relative to deal flow in the past few years. Deals greater than $100 million and $50 million in Q2 2015 are 44% and 41% lower, respectively, than the average that prevailed in the 3 years prior to Q1 2015.


Source: Evaluate Energy’s M&A Deal Analytics

Oil Price Remains Suppressed

The main driver for the increase in deal value since Q1 2015 is likely to be the improvement in the oil price which ended Q1 below $50 but averaged $57 during Q2. The improvement was slight with the WTI benchmark trading in a tight band and never breaking out higher than $62 during the quarter and this therefore kept a lid on companies overreaching themselves financially. There are many factors affecting the oil price currently, making it hard to predict where it will go for the rest of the year. Rig counts and inventories are continuing on a downward trend in the US, which supports an upward pressure on the price, but at the same time OPEC is standing resolute at its decision to refrain from cutting oil production in its latest meeting in June and perhaps more importantly, there is the possibility of a big influx of oil into the market should Iran reach a nuclear deal that eases sanctions on its oil exports.

Market unsure of the value of BG

With what was the largest deal of the quarter and also of the past 17 years in the oil industry, Royal Dutch Shell agreed to acquire BG Group for $84 billion. The terms of the offer implied a healthy premium of 51% on the trading price of BG and there is a wide disparity in views on whether or not the deal represents good value for Shell. On the one hand, Shell is purchasing BG at a historically opportune time after the widespread drop in market capitalisations in the industry and the BG assets represent a good fit with Shell’s portfolio. On the other hand, with the low oil price currently prevailing in the market, the deal represents an EBITDA and cash flow multiple of 15 and 22 times respectively, based upon annualized Q1 2015 results, which are figures far higher than a typical corporate buyout in the industry of 5-10x. The fact that the share price of Shell has dropped by 14% since the day of the announcement shows that the doubters are currently exerting more influence than the believers in the deal.

Pacific Rubiales and Dragon Oil Consolidated by Parent Companies

ALFA, S.A.B. de C.V. made a move to increase its interest in Colombian operator Pacific Rubiales Energy Corp. – one of the largest producers on the Toronto Stock Exchange – from 18.95% to 100% for a total, all-cash value of $5 billion in the second largest deal of the quarter. Emirates National Oil Co (ENOC) is acquiring the remaining 46.1% of UK-listed Dragon Oil for $2.6 billion in what is the fifth largest deal of the quarter. ENOC’s previous attempt at consolidating Dragon Oil in 2009 broke down after failing to gain approval of a sufficient percentage of shareholders and it may not be coincidence that the Dragon Oil shareholders viewed ENOC’s approach this time as a good opportunity to cash out at a time of uncertainty in the market. 

Noble Opportunistically Acquires Rosetta Resources

Noble Energy emerged as the first company since the oil price slump to make a large corporate buyout in the US shale industry, the industry that has arguably been hardest hit in the past 7 months as global commodity prices fell. Rosetta’s debt to equity level stood at 119.8% at the end of 2014, which increased to 137.1% in Q1 2015 and would likely have risen further in Q2 2015 had Noble Energy not come in with a $3.9 billion offer, including debt. The timing of the deal means that Noble will be gaining Rosetta at a time when its enterprise value offered a 40% discount compared to 9 months ago, despite production rising 7% since this time and reserves remaining unchanged.

Itochu’s Samson Resources Relinquishment Reveals Struggle in the Shale Industry

Itochu was part of a consortium that acquired Samson Resources for $7.2 billion in 2011, a time when the US shale industry was in full strength and having an exposure to the burgeoning industry was seen as a prudent strategy by most large diversified oil companies. During Q2 2015, Itochu uncovered the current dire state of operations in the industry with a sub $60 oil price, by handing back their 25% interest in Samson for a nominal consideration of $1. The deal is the ninth largest oil and gas deal of the quarter on account of the $4 billion debt that Samson had on its balance sheet at the time of the announcement.

Total Q2 2015 Deal Statistics


Source: Evaluate Energy’s M&A Deal Analytics


When the oil price slumped at the tail end of 2014, companies across the industry quickly reverted to survival mode; cutting capex and discretionary costs in order to see out however long the low oil price environment would last. It’s now been 7 months since the oil price dropped lower than the marginal breakeven cost and with each month that the oil price remains low will be another month of strain on the balance sheet of companies in the industry, increasing the possibility of distressed corporate sales. With Royal Dutch Shell being the only major so far to make a significant move, the below table shows the companies best placed to pick off any struggling companies in the coming quarter. Assuming that a debt-to-capital-employed level of 35% is still a healthy level to operate within, the table below shows the top ten global oil and gas companies ranked on their capacity to take on further debt to fund opportunistic acquisitions (data taken from Evaluate Energy’s financial and operating database as per first quarter 2015 financial accounts).


Source: Evaluate Energy

Top 10 Deals During Q2 2015


Source: Evaluate Energy’s M&A Deal Analytics


All data here is taken from the Evaluate Energy M&A database, which provides Evaluate Energy subscribers with coverage of all E&P asset, corporate and farm-in deals back to 2008, as well as refinery, LNG, midstream and oil service sector deals.

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The Top 100 Canadian Oil & Gas Companies

Posted by Mark Young

Jun 24, 2015 9:09:00 AM

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 2015 Canadian oil & gas production results from all TSX and TSX-V listed Canadian oil and gas companies in the CanOils database.

Strong Operational Gains Marred by Falling Commodity Prices

Regardless of which companies climbed the rankings or which companies fell, Q1 2015’s low commodity prices have had an impact on everyone. Paramount Resources Ltd. (achieved a climb of 3 places to 26th this quarter) is one company that is a very interesting case study here to show just how hard the industry has been hit by falling prices. The company posted an 82% increase in average production from Q1 2014, 21,028 boe/d, to Q1 2015, 38,317 boe/d. Despite this, the company saw its sales revenue actually decrease by 7% to C$80.2 million, after its realised prices for oil and condensate in the same period fell by 52% to C$48.91/bbl from C$99.55/bbl. 

Price Downturn & Pipeline Curtailments Cause Production Cutbacks

The biggest and most significant falls in the top 100 rankings this quarter were mainly caused by two factors. One of these factors was the commodity price collapse at the end of 2014, which caused many companies to shut in uneconomic production in Q1 2015. Crew Energy Inc. shut in around 800 boe/d of uneconomic Lloydminster heavy oil production, for example, and dropped 4 places in the rankings to 40th. The other factor that was a common cause of production decreases in Q1 2015 was TransCanada pipeline curtailments; Peyto Exploration & Development Corp. (the only company to drop a place in the top 25), Bonterra Energy Corp. and Delphi Energy Corp. all had difficulties with TransCanada that caused a cut back in production.

The quarter's highest climber, Iona Energy Inc., ended Q1 2015 with an average of 1,707 boe/d, having mostly recovered from its own pipeline difficulties in the UK North Sea, which saw its Q4 2014 production limited to only 418 boe/d.


Source: CanOils via Canada's Top 100 Oil & Gas Companies, March 2015

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


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



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Alberta Oil & Gas Production Falls in Q1 2015

Posted by Mark Young

Jun 19, 2015 9:47:00 AM

Q1 2015 saw a significant fall in oil and gas production across Alberta, with many companies recording large declines in core operating areas compared to the end of 2014.

Between Q3 2014 and Q1 2015, overall Alberta production – excluding oil sands – has fallen by 8% (56,880 boe/d) and between Q4 2014 and Q1 2015, overall production has fallen by 5% (34,165 boe/d). This is due to a number of factors; the fall in global commodity prices is perhaps the major reason for this decline, but companies have also suffered due to other external pressures such as pipeline difficulties or maintenance periods, for example.

CanOils Assets is a powerful new tool that can identify both where production declined to the greatest degree and which companies recorded the biggest net decline. Find out more about CanOils Assets.

In Which Regions has Production Declined the Most?

Alberta is divided into 7 regions by the Petroleum Services Association of Canada ("PSAC Regions" – see note 1) and the production from each for any given period can be quickly downloaded from the CanOils Webmap. The data shows that, excluding oil sands production, all PSAC regions in Alberta with the exception of the Foothills region have recorded declines in quarterly production since Q3 2014 when commodity prices began to fall.  


Source: CanOils Assets


Source: CanOils Assets (Foothills PSAC region excluded here as production in that region increased)

NW Alberta had the biggest drop between Q3 2014 and Q1 2014 (11%, 24,888 boe/d) and Foothills Front is the biggest % drop between Q4 2014 and Q1 2015 (7%, 14,077 boe/d). These charts were built using the combined total monthly production of all non-oil sands wells in Alberta.

Identifying the Companies with the Biggest Declines in Production

As CanOils Assets has working interest information for every well in Alberta, British Columbia and Saskatchewan, this analysis can be taken further to look at each individual company’s performance and identify the companies that recorded the biggest declines in the Foothills Front and Northwest Alberta PSAC regions. A rundown of the top 5 in each region (exclusive of asset divestiture activity, see note 2) is shown below.

Table 1: NW Alberta – Biggest Production Volume Declines Between Q3 2014 and Q1 2015


Source: CanOils Assets (See note 2)

Table 2: Foothills Front – Biggest Production Volume Declines Between Q4 2014 and Q1 2015Alberta_PSAC_Prod4_Jun15

Source: CanOils Assets (See note 2)

With asset sales removed from consideration here, possible explanations for recording a decline in production between two periods include the following:

  • Natural decline – maturing wells produce at a lower rate as time goes on. A lack of new drilling will also make natural decline more pronounced in the data, as new wells would normally replace production lost to maturing assets
  • Production being shut-in or choked-back – production deliberately being suspended or slowed down for a variety of reasons, which could include maintenance, price concerns or difficulties with pipeline operators
  • Poor well performance – new wells being drilled may not have as good an initial production rate as wells drilled in the past

Please contact us to find out how CanOils Assets can be utilised to distinguish between these possibilities on a company by company basis, unravel company strategies and provide valuable, timely insights on industry trends. 



1) The Petroleum Services Association of Canada (PSAC) divided Alberta into 7 regions based on service areas with similar costs. The 7 regions are, in alphabetical order, Central Alberta, East Central Alberta, Foothills, Foothills Front, Northeast Alberta, Northwest Alberta and Southeast Alberta. http://www.energy.alberta.ca/Oil/pdfs/RISConvTechInvestorCompar.pdf

2) Production figures in Q4 2014 in Foothills Front and production figures in Q3 2014 in Northwest Alberta have been normalised for asset sales between these respective periods and Q1 2015 for the companies in question. By removing asset sales, the data now shows the companies that recorded a reduced level of production from the same asset base between periods. Without this, Encana Corp., for example, would be very high on the Foothills Front table as it recorded a huge drop in production between Q4 2014 and Q1 2015, but a very high percentage of this is attributable to the sale of coalbed methane assets to Brookfield Asset Management Inc. 

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