Author: Mark Young

Chesapeake Bankruptcy: Key Insights from 2010-2020 Data

From riding high to bankruptcy, Chesapeake Energy Corporation’s decline will shock many in the industry. Evaluate Energy has tracked Chesapeake’s cash and financing gap over 10 years, showing major spending above and beyond its own earnings earlier this decade.

  • Production grew 69 per cent from 431,000 boe/d to 730,000 boe/d between Q1 2010 and Q4 2014. Growth was financed only in part by organic, operating cash flow, which lagged capital expenditure.
  • Chesapeake spent almost US$30 billion more in capex between 2010 and 2014 (excluding any asset acquisitions) than it generated from operations.
  • The finance gap was covered by asset sales and debt. Over the four-year growth period, operating cash flow was half the combined sum of cash generated.

  • In late 2014, the price crash hit and Chesapeake’s typical sources of cash dried up. New debt became unavailable — the company took on a net sum of zero new debt in 2015 — and asset sales have remained a fraction of the size of pre-2014 cash inflow.
  • Despite the lack of cash generated from asset sales, the company did see its production fall to hit its operating cash flow.
  • Fast-forward to the end of 2019 and Q1 2020, and the growth that took years of heavy investment has disappeared.
  • Q1 2020 production for Chesapeake was 479,000 boe/d, only 11 per cent larger than Q1 2010 and a 34 per cent reduction on the peak production levels seen in Q4 2014. With less operating cash flow, and very little opportunity to take on debt or sell assets like before, Chesapeake’s original debt levels were looming large.

All data here was extracted from Evaluate Energy’s financial and operating database.

For more on Evaluate Energy’s financial and operating database, please click here.

Alternatively, find out about our full product range at this link.

Free Webinar – June 2, 2020: How did hedging impact Q1 results?

Q1 results continue to pour out for North American oil and gas producers, with many recording severe cuts in revenues and impairments to their asset bases thanks to COVID-19 and a lack of demand for oil.

Evaluate Energy will be holding a free webinar on June 2, 2020, focusing on how hedging strategies boosted Q1 results amongst all this turmoil. The webinar will also look ahead, showing how far companies have gone to protect themselves for the rest of 2020.

To find out more about the webinar, click here.

The webinar will build on the early estimates we were able to make from annual filings in our previous webinar that was held on May 6.
Below are some of the pricing statistics we published for that discussion, where we saw that plenty of companies had managed to hedge at over $50 for 2020.

Example Pricing Information for North American Hedging – indexed to WTI (US$/bbl)

Source: May 6 Webinar deck, to be updated for next webinar June 2, 2020

We also showed that based on all contracts or hedging positions in place for 100+ producers according to annual filings and by using WTI and Brent prices as of April 13, we would have expected over $23 billion in hedging gains for 2020 and $27 billion for all periods combined.

Source: May 6 Webinar deck, to be updated for next webinar June 2, 2020

For our next webinar we will be able to go deeper with more concrete information.

The limitation in early May, of course, was that all the data we looked at was made available before the price began to crash. Although the price did not begin to fall until mid-March, plenty of companies have had to adjust their portfolio before Q1 results were released.

Using Q1 data dated March 31 that is now available to us, we can take a better look at how companies began to respond in the immediate wake of the price crashing. This will provide you with a far better indication of:

  • How well protected North America’s oil producers are, should these lower prices stick around for the longer-term.
  • Estimated hedging gains expected in 2020 and beyond.

To sign up for the webinar and to see a full overview of the topics set to be covered, click here.

$10.7 billion in new Latin American upstream deals in 2019

Thanks to a handful of major deals valued at over $1 billion, 2019 saw the largest overall M&A spend in the upstream sector over the past five years for Latin American assets.

This is according to the latest report from Evaluate Energy, the Daily Oil Bulletin and Sproule.

The report, entitled Latin America: 2019 Upstream M&A and Drilling Activity Review, provides a detailed overview of the key M&A trends and drilling activity in Latin America in recent years. It is available to download here.

Source: Latin America M&A and Drilling Review, 2019 – Download Here.

The two largest deals took place in Suriname and Brazil – the details of each deal are provided below.

Suriname – Total enters Block 58 in deal with Apache

As the chart above shows, this one deal for $5.1 billion pushed Suriname into third place when ranking each Latin American nation by upstream M&A activity in US$ since 2014. The deal itself was a farm-in arrangement that sees Total join Apache Corp. in Block 58.
Total will gain a 50% interest in the block, with the consideration made up of a $100 million upfront cash payment and a cost-carry where Total will pay $5 billion of Apache’s development costs for the first $15 billion of development expenditure. The deal includes a bonus due to Apache on first oil, as well as royalties and ongoing cost carries if costs escalate further.

Brazil – Petrobras agrees deal with Petronas

Brazil is still Latin America’s leading nation over the five-year period covered in the report, with over $14 billion in new upstream deals agreed since the start of 2014.

State-company Petrobras has played a pivotal role in this total, especially in the past 12 months. The company agreed 10 individual asset sales last year for a total of $3.5 billion in 2019 alone. The largest of its 2019 deals was this $1.29 billion sale to Petronas, where the Malaysian company acquired non-operated interests in the Tartaruga Verde field and Module III of the Espadarte field.

More on each deal, as well as details on 2019’s other +$1 billion deal that was agreed with Peru, can be found in the report.

Also included in the report:

  • How much of an impact COVID-19 and early 2020 pressures have had on future plans across the region
  • Expert analysis from Sproule on all the latest developments for Latin America
  • Details on the largest and most significant upstream M&A activity in 2019
  • Bidding round reviews and key transactional trends
  • Information on future drilling and investment initiatives across the region
  • Country-by-country analysis for all major producing nations

Download the full report at this link.

 

Colombia is “Latin America’s poster child” for attracting upstream investment

Colombia’s knack for innovation and cultivating a stable, positive relationship with its E&P industry at large have been key factors for the nations success in attracting foreign investment.

This is according to Jorge Milanese, Sproule’s Regional Director for Latin America, co-author of a new report from Sproule released in partnership with Evaluate Energy and the Daily Oil Bulletin.

The report, entitled Latin America: 2019 Upstream M&A and Drilling Activity Review, provides a detailed overview of the key M&A trends and drilling activity in Latin America in recent years.

The report can be downloaded at this link.

“Colombia is such an exciting nation to watch,” Milanese said. “It is constantly on the lookout for innovative initiatives to spark outside investment, be it through bidding rounds, infrastructure development or regulatory frameworks.”

Colombia ranks fourth in terms of the total deal value for upstream transactions in each Latin American nation since the start of 2014, lagging far behind Brazil and Argentina in particular – but this is not an issue according to Jorge Milanese.

Source: Latin America M&A and Drilling Review, 2019 – Download Here

“The nation may not see the high value deals we’re more used to seeing in Brazil or Argentina for example, but it has bee a hotbed of activity with lots of transactions taking place,” he continued. “Colombia’s relationship with the upstream industry means that business opportunities present themselves very often, which can be seen in the data we include in the report.

“The sheer number of corporate deals in Colombia over the past five years, where one company acquires another, speaks volumes to the investment possibilities that exist here and how willing companies are to make significant outlays, relative to their own individual sizes.”

The report includes details on these Colombian upstream corporate M&A transactions, including the biggest deal of 2019 that involved GeoPark Ltd. acquiring Amerisur Resources Plc for around $281 million, net of cash acquired.

Also included in the latest Latin American M&A and Drilling Activity Review for 2019:

  • Jorge Milanese’s top 4 areas to watch as Colombia’s upstream industry continues to develop
  • Details on the largest and most significant upstream M&A activity in 2019
  • Bidding round reviews and key transactional trends
  • Information on future drilling and investment initiatives across the region
  • Country-by-country analysis for all major producing nations
  • How much of an impact COVID-19 and early 2020 pressures have had on future plans across the region

The report can be downloaded at this link.

 

Q1 2020 sees just $21 billion in new upstream deals

In Q1 2020, a total of just US$21 billion in new upstream oil and gas M&A deals were agreed against a torrid backdrop of COVID-19 demand decline and an industry price war.

Evaluate Energy’s latest quarterly review of global M&A activity in the upstream sector shows that only four quarters since the start of 2014 saw less than $21 billion in new deals, and no quarter saw fewer deals valued at over US$50 million.

The report, which has been produced in partnership with Deloitte, is available to download at this link.

Source: Evaluate Energy M&A Review, Q1 2020

The impact of the price war and COVID-19 can be seen by looking at monthly activity, according to report author, Eoin Coyne, senior analyst at Evaluate Energy.

“The majority of Q1’s deal value occurred in the first two months of 2020,” he said. “This was at a time when OPEC+ was still supporting the oil price and when there was still hope that countries beyond the Asia Pacific region could avoid the spread of COVID-19.

“In March 2020, there was just $0.2 billion of deals announced other than a large acquisition by the Russian government, which can be argued isn’t representative of free market demand.”

Alongside this analysis centred around COVID-19, this quarter’s report also includes details on:

  • An 11-year low in deals in the United States
  • Activity for ConocoPhillips, Premier Oil, Equinor and Shell
  • The largest deals of the quarter, which took place in Latin America
  • The main Canadian events in another quiet quarter

 

How are Canada’s private operators navigating the downturn?

We have seen countless headlines and in-depth analysis pieces focusing on global supermajors, OPEC+ nations and public companies around the world are trying to cope with the new pressures presented by the COVID-19 pandemic as demand for oil has plummeted and storage space is drying up.

But coverage on how private companies are dealing with the downturn has been pretty scarce up to now.

Our partners at the Daily Oil Bulletin have released a new article looking at how private companies in Canada are faring during this unprecedented price downturn.

The full article can be accessed here.

The article focuses on how different it is being a privately-held firm compared to being publicly listed in these times, gathering insight from a number of Canada’s largest producers. The article provides outlooks for both Canadian natural gas prices and acquisition opportunities.

According to CanOils Assets data, Alberta holds most of Canada’s top private producers going by operated volumes.

For more information on CanOils Assets, click here.

For more information on the Daily Oil Bulletin, watch this video.

Website: www.dailyoilbulletin.com

 

2019 Lays Positive Foundations for Latin America’s Upstream Sector

2019 was a very positive year for the Latin American upstream industry, according to analysis provided in the latest report released by Evaluate Energy, the Daily Oil Bulletin and Sproule.

Drilling activity and M&A transactions laid some important foundations for the future.

Data in the report shows that 2019 saw record overall M&A spending ($10.7 billion) compared to any other year since 2014, with Brazil, Suriname and Peru, in particular, seeing important transactions take place.

Source: Latin America M&A and Drilling Review, 2019 – Download Here.

“I believe that eventually we will look back at 2019 as a very important year in the history of the developing Latin American oil and gas industry,” said Jorge Milanese, Sproule’s Regional Director for Latin America and co-author of this new report.

“We saw a number of key discoveries made across the region after widespread pioneering drilling work, significant M&A transactions being made and plenty of other, related preparation work for what we expect to be a busy future ahead, once the industry resets post-pandemic.”
On the M&A front, Milanese was especially encouraged by activity taking place that involved companies that are not major IOCs or state-owned enterprises.

“2019 offered opportunities for smaller companies to gain access into key Latin American upstream markets,” he said. “Colombia continues to innovate as Latin America’s poster child for attracting foreign investment with pioneering bidding round ideas and close collaboration with the upstream industry.”

“Meanwhile in Brazil, an interesting dynamic is developing that is opening up possibilities for smaller companies. Typically, deepwater rounds attracted larger IOCs, but recently companies have been rationalising their portfolios. The larger IOCs are now selling assets to mid-size and domestic companies, who in turn are going through a similar process and selling their assets to even smaller companies.”

For more on the key developments in Brazil, Colombia and the rest of Latin America, download the full report from Evaluate Energy, the Daily Oil Bulletin and Sproule at this link.

Also included in the latest Latin American M&A and Drilling Activity Review for 2019:

  • Details on the largest and most significant upstream M&A activity in 2019
  • Bidding round reviews and key transactional trends
  • Information on future drilling and investment initiatives across the region
  • Country-by-country analysis for all major producing nations
  • The impact of COVID-19 and early 2020 pressures on future plans across the region

 

Released Today: New Forecast of COVID-19 Impact on Petroleum Demand in Key Markets

The first global petroleum demand model created by the Evaluate Energy team to forecast the COVID-19 impact on markets has been published today.

Key analysis includes the extent to which demand in the United States, China, Europe and Canada continues to decline and the pace of recovery.

Evaluate Energy forecasts that global petroleum demand will drop to a low of 64.8 million barrels a day in June 2020, from a peak of over 101 million barrels a day in late 2019. Average demand for 2020 will fall to 81.2 million barrels a day.

The model is updated weekly and packaged into a report and Excel spreadsheet, available for download. For more information visit:
https://www2.jwnenergy.com/evaluate-energy-covid-19-petroleum-demand-tool

Forecasting demand during the existing and post-COVID-19 period is influenced by infection rates, government policy and changing human behaviour. Evaluate Energy is modelling this interaction to inform its forecast.

Analysis includes the following regions:

  • North America (United States, Canada and Mexico)
  • Central & South America (notably Brazil)
  • Europe
  • Russia & Eurasia
  • Asia and Oceania (including China, Japan and India)
  • Middle East
  • Africa

Evaluate Energy (www.evaluateenergy.com) is a leading provider of essential data to Oil & Gas and Renewable Energy markets. Headquartered in the UK, it is a brand within the Glacier Resource Innovation Group – the same group that houses the Daily Oil Bulletin and JWN Energy.

 

Hedging update: Assessing the impact of today’s low prices – Free Webinar

Gain fresh insight into contract pricing and changing E&P oil and gas hedging trends in this insightful 30-minute webinar from Evaluate Energy analysts.

This will include estimates of the financial impact hedging will have on upstream industry earnings.

This is a free webinar presented in partnership with the Daily Oil Bulletin and JWN Energy.

Presentations and discussions will include:

  • Estimates of the financial impact hedging will have on upstream industry earnings
  • Pricing for oil contracts in place at year-end 2019 for the rest of 2020
  • Discussion on the types of producer involved in hedging in North America
  • The most popular derivatives used across the industry, how things have changed over time, and what this tells us about risk appetites for North American producers
  • Estimates on the overall financial effect that recent hedging will have on industry earnings
  • Data usually only available exclusively to Evaluate Energy subscribers

This free webinar takes place on Wednesday, May 6, 2020 at 9am MDT.

Sign up today at this link.

Q4 2019: Highest Cost Oil Producers in North America

California is home to two of North America’s highest cost oil producers by far according to latest data from Evaluate Energy.

Earlier, we looked at North America’s lowest cost oil producers – and this analysis on high-cost producers is based on the same Evaluate Energy operating and transportation expenses per barrel data for 28 companies in Q4 2019.

  • All 28 companies were based in the U.S. or Canada and produced over 10,000 boe/d in Q4 2019.
  • The companies only produced in North America and oilsands producers were excluded.
  • To avoid gas production skewing the results, only companies with portfolios made up of over 70% oil were included.
  • Production tax costs in the U.S. are excluded, as are royalty expenses in Canada.

Low cost production is just one key indicator that investors and industry observers will be looking for in order to identify oil producing companies more likely to make it through the current downturn.

Our key conclusions from looking at the operating and transportation expenses (“production costs”) for the higher-cost producers of the group are as follows.

Source: Evaluate Energy

Overall portfolios must be considered

As we did in our earlier post on low cost producers, we paid very close attention to the trend line on the chart, calculated using the production costs of all companies in the group. It shows that as oil weighting increases, so does the average cost per barrel to produce for each company.

Therefore, knowing a company’s cost per barrel does not immediately help you identify high- or low-cost producers, you must know what the costs are relative to its particular portfolio before drawing any conclusions.

High cost producers, based on production costs and portfolio

California is home to the two highest cost producers of the group, relative to their portfolios. California Resources Corporation (CRC) and Berry Petroleum Corporation (BRY) lie furthest from the trend line out of all companies in the group on both the high- and low-cost ends of the spectrum. The costs are so high here at $18.67 and $21.44, respectively, that they are almost anomalies in the data set. They drag the trend line upwards, which is causing some of the lower cost operators to look much better off than they probably should.

As for the other companies appearing to have higher costs than the others, enhanced-oil recovery focused Denbury Resources Inc. (DNR) has the highest cost per barrel of the whole group in pure dollar terms at $22.46/boe. The company is also the most oil-focused of the group so that plays a significant role here.

Battalion Oil Corp (BATL) is also among the higher cost companies of the group at $13.53/boe for a 75% oil portfolio. The company is now focused on the Permian after a recent restructuring and emergence from Chapter 11 bankruptcy proceedings in the third quarter of 2019.

The highest cost Canadian operator relative to the trend line was Cardinal Energy Ltd. (CJ). The company has a portfolio made up of 88% oil and recorded a Q4 production cost of C$20.58/boe.

Costs aren’t everything – bigger picture required

It is important to point out, of course, that a company’s health cannot be determined by taking only its production costs into account. Relatively high costs alone aren’t necessarily a reason for panic. Costs merely form one piece of the puzzle.

To illustrate this, we’ll draw on the example of Whiting Petroleum. The company is part of this analysis group and recorded operating and transportation costs of $7.28/boe, between $2-$3 below the trend line for a company of its oil weighting (82%). Relatively low costs alone did not save the company from filing for Chapter 11 bankruptcy, which was announced at the start of April, due to its debt position.

About Evaluate Energy
Evaluate Energy data allows detailed analysis of oil and gas company health, liquidity and performance to help determine the immediate and long-term outlook for oil and gas producers around the world. For more information on Evaluate Energy, click here.