If I had to lay odds on which E&P powerhouse is going to secure the sector’s next major corporate acquisition I’d start by examining their ability to absorb substantial levels of debt while still keeping debt-to-capital ratios in balance.
Sightings of large corporate mergers have been rare during the commodity price downturn. During that time, the number of companies with high debt-to-capital ratios has soared. To help understand which oil giants have the financial clout to pull together a major M&A deal, we’ve shortlisted those with the greatest ability to assume debt and remain “healthy”.
Companies with greatest debt capacity as of Q1 2016
By assigning an arbitrary debt-to-capital ratio of 35% as “healthy” you can see which companies are currently able to assume the most extra net debt for a corporate acquisition either in Canada or internationally, and still keep debt levels in check. For example, Tourmaline Oil Corp. (TSX:TOU) would be able to assume Cdn$799 million extra net debt in any acquisition in this model, based on its Q1 2016 balance sheet, before its debt-to-capital ratio exceeded 35%.
Of course, this doesn’t necessarily mean these companies will seek a merger deal. But if they do, they’ll have plenty of capacity for additional debt assumption.
More details on this can be found in the webinar I delivered last week, which can be viewed here.
Why is debt important to consider NOW?
It’s true that the general capital profile of an upstream oil and gas company has, on the whole, changed dramatically since the price downturn began. Looking at U.S. and international companies that report to the SEC as well as every TSX company, we can see a general increase in risk since last year by looking at those debt-to-capital ratios. The findings are intriguing:
In 2015, debt was a much greater proportion of their entire capital structure than 2014. That’s hardly a major surprise given the downturn. Some companies even moved into a negative equity position in 2015, as pressures from a longer period of low commodity prices mounted.
Analysis: Biggest corporate deals of the downturn
The highest profile global corporate merger during the downturn was undoubtedly Royal Dutch Shell’s (LSE:RDSA) acquisition of BG Group for around US$81 billion. In Canada, it was Suncor Energy’s (TSX:SU) Cdn$6.6 billion acquisition of Canadian Oil Sands Ltd. (COS) to become the largest stakeholder in the Syncrude project.
Both deals had a lot in common: a large issuance of stock in the acquiring company to the target, as well as the assumption of significant debt.
June 2016 has also seen a couple more deals in Canada that follow this debt assumption pattern.
It’s this ability to assume debt and still remain healthy that we think is crucial in identifying those most likely to take on a big corporate merger in the near future.
Both Suncor and Royal Dutch Shell appear in our above list of companies with high debt capacity. Suncor has been linked to more acquisition activity in press reports, while Shell has not – having actually been linked with more asset sales than purchases. In fact, rumours came out of the company that Shell assets were going to hit the market in ten countries worldwide in the not-too-distant future.
Of the other companies listed with greatest debt capacity, many have been selling high-value royalty assets in Canada to bolster their activities with significant cash through the downturn, while the international list includes some of the world’s biggest and most powerful companies.
With companies also having put copious funding into cost controls in recent times and oil prices starting to trend upwards a bit, we might just be around the corner from one of the companies on this list making the world’s next big corporate merger in the E&P sector and we should expect it to include the significant assumption of debt.
1) To value all acquisitions where stock is used as part of the consideration, Evaluate Energy and CanOils always use the day prior share price. Sometimes companies use a deemed stock value or a weighted average price in their press announcements to value the stock, but for comparability reasons, we always use the same method for every deal. This may create some slight discrepancies between our data and announced deal values. Gear valued its acquisition of Striker based on its concurrent bought deal financing, rather than its trading share price, and reported a value of Cdn$63.7 million.
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At first, it seemed like a done deal. Chevron made a US$33 billion offer to take over US-based upstream independent Anadarko Petroleum. It was a 39% premium to Anadarko’s last traded price at the time and would have been the largest industry deal since Shell’s US$61 billion takeover of the BG Group in 2015. The deal would have given Chevron significant and synergistic acreage in the Permian Basin along with new potential in US midstream, as well as Anadarko’s high potential projects in Africa. Then Occidental Petroleum swooped in at the eleventh hour, making the delicious new bid and pulling the carpet out from under Chevron.
We can thank Warren Buffet for this. Occidental Petroleum, or Oxy, had previously made several quiet approaches to purchase Anadarko. These were rebuffed in favour of Chevron’s. Then Oxy’s CEO Vicki Hollub took the company jet to meet with Buffet. Playing to his reported desire to buy into shale, Hollub returned with a US$10 billion cash infusion from Buffet’s Berkshire Hathaway – which was contingent on Oxy’s successful purchase of Anadarko. Hollub also secured a US$8.8 billion commitment from France’s Total to sell off Anadarko’s African assets. With these aces, she then re-approached Anadarko with a new deal – for US$38 billion.
This could have sparked off a price war. After all, the Chevron-Anadarko deal made a lot of sense – securing premium spots in the prolific Permian, creating a 120 sq.km corridor in the sweet spot of the shale basin, the Delaware. But the risk-adverse appetite of Chevron’s CEO Michael Wirth returned, and Chevron declined to increase its offer. By bowing out of the bid, Wirth said ‘Cost and capital discipline always matters…. winning in any environment doesn’t mean winning at any cost… for the sake for doing a deal.” Chevron walks away with a termination fee of US$1 billion and the scuppered dreams of matching ExxonMobil in size.
And so Oxy was victorious, capping off a two-year pursuit by Hollub for Anadarko – which only went public after the Chevron bid. This new ‘global energy leader’ has a combined 1.3 mmb/d boe production, but instead of leveraging Anadarko’s more international spread of operations, Oxy is looking for a future that is significantly more domestic.
The Oxy-Anadarko marriage will make Occidental the undisputed top producer in the Permian Basin, the hottest of all current oil and gas hotspots. Oxy was once a more international player, under former CEO Armand Hammer, who took Occidental to Libya, Peru, Venezuela, Bolivia, the Congo and other developing markets. A downturn in the 1990s led to a refocusing of operations on the US, with Oxy being one of the first companies to research extracting shale oil. And so, as the deal was done, Anadarko’s promising projects in Africa – Area 1 and the Mozambique LNG project, as well as interest in Ghana, Algeria and South Africa – go to Total, which has plenty of synergies to exploit. The retreat back to the US makes sense; Anadarko’s 600,000 acres in the Permian are reportedly the most ‘potentially profitable’ and it also has a major presence in Gulf of Mexico deepwater. Occidental has already identified 10,000 drilling locations in Anadarko areas that are near existing Oxy operations.
While Chevron licks its wounds, it can comfort itself with the fact that it is still the largest current supermajor presence in the Permian, with output there surging 70% in 2018 y-o-y. There could be other targets for acquisitions – Pioneer Natural Resources, Concho Resources or Diamondback Energy – but Chevron’s hunger for takeover seems to have diminished. And with it, the promises of an M&A bonanza in the Permian over 2019.
The Occidental-Anadarko deal:
Source: U.S. Energy Information Administration, Short-Term Energy Outlook
In April 2019, Venezuela's crude oil production averaged 830,000 barrels per day (b/d), down from 1.2 million b/d at the beginning of the year, according to EIA’s May 2019 Short-Term Energy Outlook. This average is the lowest level since January 2003, when a nationwide strike and civil unrest largely brought the operations of Venezuela's state oil company, Petróleos de Venezuela, S.A. (PdVSA), to a halt. Widespread power outages, mismanagement of the country's oil industry, and U.S. sanctions directed at Venezuela's energy sector and PdVSA have all contributed to the recent declines.
Source: U.S. Energy Information Administration, based on Baker Hughes
Venezuela’s oil production has decreased significantly over the last three years. Production declines accelerated in 2018, decreasing by an average of 33,000 b/d each month in 2018, and the rate of decline increased to an average of over 135,000 b/d per month in the first quarter of 2019. The number of active oil rigs—an indicator of future oil production—also fell from nearly 70 rigs in the first quarter of 2016 to 24 rigs in the first quarter of 2019. The declines in Venezuelan crude oil production will have limited effects on the United States, as U.S. imports of Venezuelan crude oil have decreased over the last several years. EIA estimates that U.S. crude oil imports from Venezuela in 2018 averaged 505,000 b/d and were the lowest since 1989.
EIA expects Venezuela's crude oil production to continue decreasing in 2019, and declines may accelerate as sanctions-related deadlines pass. These deadlines include provisions that third-party entities using the U.S. financial system stop transactions with PdVSA by April 28 and that U.S. companies, including oil service companies, involved in the oil sector must cease operations in Venezuela by July 27. Venezuela's chronic shortage of workers across the industry and the departure of U.S. oilfield service companies, among other factors, will contribute to a further decrease in production.
Additionally, U.S. sanctions, as outlined in the January 25, 2019 Executive Order 13857, immediately banned U.S. exports of petroleum products—including unfinished oils that are blended with Venezuela's heavy crude oil for processing—to Venezuela. The Executive Order also required payments for PdVSA-owned petroleum and petroleum products to be placed into an escrow account inaccessible by the company. Preliminary weekly estimates indicate a significant decline in U.S. crude oil imports from Venezuela in February and March, as without direct access to cash payments, PdVSA had little reason to export crude oil to the United States.
India, China, and some European countries continued to receive Venezuela's crude oil, according to data published by ClipperData Inc. Venezuela is likely keeping some crude oil cargoes intended for exports in floating storageuntil it finds buyers for the cargoes.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook, and Clipper Data Inc.
A series of ongoing nationwide power outages in Venezuela that began on March 7 cut electricity to the country's oil-producing areas, likely damaging the reservoirs and associated infrastructure. In the Orinoco Oil Belt area, Venezuela produces extra-heavy crude oil that requires dilution with condensate or other light oils before the oil is sent by pipeline to domestic refineries or export terminals. Venezuela’s upgraders, complex processing units that upgrade the extra-heavy crude oil to help facilitate transport, were shut down in March during the power outages.
If Venezuelan crude or upgraded oil cannot flow as a result of a lack of power to the pumping infrastructure, heavier molecules sink and form a tar-like layer in the pipelines that can hinder the flow from resuming even after the power outages are resolved. However, according to tanker tracking data, Venezuela's main export terminal at Puerto José was apparently able to load crude oil onto vessels between power outages, possibly indicating that the loaded crude oil was taken from onshore storage. For this reason, EIA estimates that Venezuela's production fell at a faster rate than its exports.
EIA forecasts that Venezuela's crude oil production will continue to fall through at least the end of 2020, reflecting further declines in crude oil production capacity. Although EIA does not publish forecasts for individual OPEC countries, it does publish total OPEC crude oil and other liquids production. Further disruptions to Venezuela's production beyond what EIA currently assumes would change this forecast.
Headline crude prices for the week beginning 13 May 2019 – Brent: US$70/b; WTI: US$61/b
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