Oil Majors Reported Earnings Last Week

Last week, Major Oil Companies reported earnings. Below is a list of the major oil and gas companies, and what they reported:

Eni (NYSE: E):Q2 EPS of -€0.27
ExxonMobil (NYSE: XOM):Q2 EPS of $0.41 (misses by $0.23)
Chevron (NYSE: CVX):Q2 EPS of -$0.78 (misses by $1.10)
ConocoPhillips (NYSE: COP)Q2 EPS of -$0.79 (misses by $0.18
Total (NYSE: TOT)Q2 EPS of $0.90 (beats by $0.16)
Royal Dutch Shell (NYSE: RDS.A)Q2 EPS of $0.13
Total (NYSE: TOT)Q2 EPS of $0.90 (beats by $0.16)
Royal Dutch Shell (NYSE: RDS.A)Q2 EPS of $0.13
BP (NYSE: BP): Q2 EPS of $0.23 (misses by $0.05)
Pioneer Natural Resources (NYSE: PXD): Q2 EPS of -$0.22 (beats by $0.12)
Suncor Energy (NYSE: SU)Q2 EPS of -$0.36 (misses by $0.15)
Anadarko Petroleum (NYSE: APC)Q2 EPS -$0.60 (beats by $0.20)

(see: http://oilprice.com/Energy/Energy-General/Oil-Industry-Slammed-By-Disappointing-Earnings-Oil-Price-Plunge.html

While we will not cover every Company listed above, I combed the transcripts and found the following important information for you all (of course, I have tried to highlight the most significant portions and I want to thank www.SeekingAlpha.com for transcribing the calls. All transcripts cited herein can be found on their website). I’m sorry this article is a bit long, but I literally reviewed hundreds of pages of transcripts to condense the information down to these relevant portions.


The two best overviews we got for the market came from BP and Anadarko. Key points from BP are as follows:

In speaking about current market conditions during their Q2 earnings call on July 26, 2016, BP described the current macro environment:

Let's start then with how we see the macro environment. As we expected, growth in global oil demand remains strong and we have seen some slowing in global supply growth stemming from supply disruptions, partially offset by the continued increase in Iranian production. In the United States, production continued to decline, and we anticipate a further drop in the third quarter. But with producers slowly adding back rigs, production should stabilize by year end.

While some of the factors that have recently supported oil prices may only be temporary, we see the overall fundamentals bringing the market into balance during the second half of this year. Over the last quarter, we have seen oil prices strengthen in anticipation of this rebalancing, with some weakening primarily due to the strong dollar in the last week or so.

The longer-term fundamentals for the industry also remain robust. However, for the time being, oil inventories remain high, well above their five-year average, shown in the green band, and these inventories could still hold back further increases in oil prices for a while yet. So the forward curve has flattened, although it still remains positive. Markets also remain cautious as they await more clarity around the impact of Brexit on oil demand.

BP indicated that while they expect the market to be challenging, they also expect to see more support for oil prices as declining production and increases in gas-fired power generation have helped to limit storage overhand and should continue to support some firming in price over the second half of the year. Further discussing world market and current conditions:

  • Speaking of the North American Market cost reductions, BP noted that the efficiency in cost reduction initiatives has driven a 33% decrease in their production costs per barrel from 2012. That translates into a reduction of around $300 million a year annualized in cost savings. So our unit production costs decreased to about $7.34 a barrel, 6% lower than the first quarter of this year.
  • Speaking about rig counts in the lower 48, BP is actually allowing some CAPEX in the second half of the year. BP had taken their rig count in the lower 48 down to 1, and they are currently operating 3-4 rigs. They believe they will be up to 5-10 rigs by the end of the year!!!!
  • On Iranian production: BP Economist Spencer Dale had forecast Iranian production to increase by 500,000 bpd. That has been achieved, but they do not seem to expect that it will continue to rise.
  • While BP did not specifically call bottom, they did say they believed we are “at the bottom of the cycle” or close to it. Furthermore, while BP Execs did not say their forecast for oil in the mid- to long- term is $50-55 per barrel, this number continuously came up and I believe that it is the number they are basing decisions on.

Speaking of future developments:

  • BP expects capital expenditure to be below the original guidance of $17 billion of 2016, and remain in the $15-17 billion range for 2017 – this represents a 30-40% drop from peak levels in 2013.
  • Global refining margin averaged $13.80 per barrel in Q2, the lowest since 2010 (compared to $19.50 a year ago)
  • BP expects 800,000 barrels of oil equivalent per day of new production by 2020. Of this, we expect 500,000 barrels of new capacity to be in place already by the end of 2017

Answering a question about the Historical U.S. Advantage on refined products and whether such advantage will continue in light of the lifting of the export ban, Tufan Erginbilgic (CEO – Downstream Operations) stated as follows:

But you talk about U.S. advantage. Frankly, U.S. advantage started to erode some time ago. It's not something new. When the U.S. actually allowed exports to take place, WTI Brent started to actually narrow, and today it is $1 – $2 around that. That plus the WTI production because of the crude price share of production going down, frankly that differential almost got lost. So U.S. advantage is no longer on the crack advantage as U.S. had to have but more the energy cost. But energy cost, if you compare rest of the world refining versus U.S., even Europe, actually that advantage is offset by lower non-energy costs in Europe versus U.S. So overall, I would say once the exports were allowed, that U.S. advantage to a great extent, not fully, but to a great extent disappeared, but not fully because WTI probably will operate on an export parity basis.



In its July 27, 2016 earnings call, several Anadarko executives, including Chairman, President and CEO R.A. Walker made the following key points:

  • U.S. oil supply appears to have peaked at around 9.6 million barrels per day and they believe it will bottom out around 8 million bpd, while global demand now exceeds expectations. They believe this bottom could be reached as early as later this year which is why they make the $60.00 per barrel call they make below.
  • Given this dynamic, I am now encouraged that a sustained $60 oil price environment is likely to emerge as we move into 2017.This price level should provide the necessary cash margins and resulting cash cycle improvements to encourage us to accelerate activity and achieve strong returns. In this scenario we would evaluate redeploying some of the incremental proceeds from asset sales towards our highest quality U.S. onshore assets later this year.”
  • Anadarko believes, that this will be a demand recovery. As noted below, they believe that a demand recovery (rather than shrinking supply) will be key to driving a sustained recovery.
  • As to when Anadarko will start new drilling projects, Mr. Walker stated “ As we approach $60, we'll invest more than we will at $43-ish in terms of where WTI is today. So we're already sort of telling you today that we anticipate with improvements that we think are forecasted, that we will start to reallocate some of our monetization proceeds, as we've described on this call.” He further stated that the more comfortable Anadarko feels that we will have a sustained $60.00/bbl, the more they will invest.

CEO R.A. Walker also addressed a very interesting question posited by Brian Singer from Goldman Sachs. Mr. Singer asked what factors would cause Anadarko to bring production back online. Mr. Walker answered as follows:

Well I'll give you my thoughts, Brian, on that. And it's simply as we see U.S. oil production cascading towards that 8 million barrels a day that I made reference to in terms of where I think it will bottom out before it starts to go back up. That will in my estimation help a lot.

And if on the demand side we continue to see 1.2 million to 1.4 million barrels per day of demand per annum through the balance of the decade, I think the combination of the two are quite significant. It's been our view that we will see this be a price recovery when it's demand-driven, rather than supply-constrained. Market forces don't work real well when you're relying on supply constraints to drive price.

But I think if you think about it as a demand function that improves annually at the cliff of 1.2 million to 1.3 million barrels a day, you can see pretty quickly that in an expanding demand relative to supply, the demand's going to move up the curve. And the intersection that creates P will put pressure on prices to move up to a level of around $60 a barrel.

After that point I mean we're going to have to see what happens from, A, a demand standpoint, B, from a cost. Are we going to see margin erosion? Are there returns and the cycling characteristics that we particularly follow with our onshore investing, are they still going to be as attractive as we thought?

So I'm not going to go beyond $60. But I think clearly in our estimation the ingredients are there for a recovery to sustain $60 price environment for next year. And I've probably been as big a bear around oil price expectations as anyone since early 2015. And I think with this, if we continue to see the characteristics I just laid out continue to be prevalent in the market, that will be a great indication to us as for what we want to do.

Looking at the forward curve, I think you know as well as I do, that's a little fragile. And as you look out further, particularly in light of our – the world we live in today and the lack of real – the lack of players in the market for the forward curve, it looks flat for a reason. Because we don't have the same participants in the curve today that we had five years or certainly 10 years ago.

So the curve itself probably is not going to be as much of an indicator of activity as the other things I just made reference to.


Speaking on behalf of Exxon Mobil on July 29, 2016, Jeffrey J. Woodbury stated the following key points during their earnings conference call report:

  • Large inventories of refined fuels have hurt the business, which has sometimes lifted the company’s profits during the two-year slump in oil prices. Refining profits fell 45.2% to $825mn.
  • With longer lateral lengths and improved completion designs, per well hydrocarbon recovery has dramatically improved. Coupled with lower drilling and completion costs, this high recovery has resulted in a nearly 70% reduction in Permian unit development costs over the past two years. Our development cost per barrel is now $8 in the Permian and less than $10 in the Bakken. Additionally, we have successfully reduced cash operating costs to approximately $8 per barrel.<
  • As a result of these cost improvements, a large part of the Permian drill-well inventory is economic at prices around $40 per barrel. Over 2,000 drill-well locations in the Permian and Bakken yield a 10% rate of return at $40 per barrel. This drill-well inventory equates to nine years of continuous drilling at 2015 rig levels, providing ExxonMobil the flexibility to progress profitable
  • short-cycle opportunities and adjust activity in response to market conditions.
  • Exxon forecast that gas is going to grow about 1.6% per year from 2014 to 2040. And LNG will triple over that time period from today's capacity.


Speaking for Chevron on July 29, 2016, CFO & VP Patricia E. Yarrington made the following points:

  • Upstream earnings, excluding special items and foreign exchange, decreased $528 million between quarters. Lower crude realizations were partially offset by lower exploration and operating expenses as well as other unrelated positive variances.
  • Downstream results, excluding special items and foreign exchange, decreased by $535 million, primarily driven by lower worldwide refining margins, partially offset by lower operating expenses.
  • Year to date, capital expenditures are down 31% when compared with 2015. We're on a trend line for 2016 C&E of $25 billion or less.
  • For 2017 – 2018, we anticipate capital expenditures between $17 billion and $22 billion. If the current price environment persists, we will revisit the bottom end of the range, as our primarily goal is to be cash balanced.

James William Johnson, EVP Upstream, stated as follows:

  • Comparing Q2 2016, to Q2 2015, Net production decreased by 68,000 barrels a day between these quarters, yielding first half 2016 production of 2.6 million barrels a day. Shale and tight production increased by 50,000 barrels a day, primarily due to growth in the Midland and Delaware Basins in the Permian with the Marcellus, Vaca Muerta, Duvernay, and Liard Basins also reflecting year-on-year growth.
  • Major capital projects increased production by 37,000 barrels a day, as ramp-ups continue at Jack/St. Malo, Chuandongbei, and Angola LNG. And Exxon saw initial production from Gorgon.
  • The table shows improvement in our drilling and completion cost performance from recent pad drilling programs. For 7,500-foot laterals in the Midland Basin, Exxon is averaging $5.6 million per well, which is a 25% reduction from what to analysts in March.
  • In addition to the Permian and other large-scale short-cycle businesses such as San Joaquin and Gulf of Thailand, Exxon has a number of attractive major capital projects that leverage previous investments. These projects all take advantage of existing infrastructure, reducing development costs and cycle time. The average development cost for these projects is around $15 a barrel.
  • In the Permian, Exxon is going to be going from six rigs to 10 rigs by the end of this year.


Chairman and CEO Ryan Lance addressed Q2 earnings for ConocoPhillips. He made the following key points:

  • Production grew year-over-year by 3%. Based on our strong year-to-date performance, and Conoco is raising the midpoint of our 2016 production guidance by 2%. They are also lowering 2016 CAPEX from 5.7 billion to 5.5 billion based on efficiency improvements really across all business lines.
  • Talking about production goals, Mr. Lance stated, “Now, let me be clear that flat production is not our goal; but at a minimum we want to sustain our existing production. Because of our low decline base production, we can keep production flat for over a decade with CAPEX of $5 billion to $6 billion.”
  • In the Lower 48, their production in the second quarter was 503,000 barrels per day. Once you adjust for asset sales, that's an underlying decrease of 17 thousand barrels a day compared to this time last year. The unconventionals produced 262,000, or down 4% from second quarter of 2015. That's better performance than they had expected, driven primarily by better well performance in the Eagle Ford and the Bakken, but also by the lag effects from our ramp down in rig activity. “Now that we're running with three rigs, we expect decline in the unconventionals to steepen somewhat in the second half of the year.”
  • Full-year production guidance was updated from 1.54 million to 1.57 million barrels per day; that's an increase of 35 thousand barrels per day or about 2% over prior guidance, while at the same time they lowered both our capital and our operating cost guidance.
  • Operating with just three rigs in the lower 48, Conoco’s production will only decline 6%.
  • On the topic of adding Rigs, Conoco executives stated: “ we don't have some set price that's going to drive us out to add rigs in the Lower 48. We do have the volume momentum that I was talking about earlier and the better volume performance we're getting from just the rigs we're running. But we're not going to get excited and rush out there and add rigs every time the price bumps up. The price since the last call, the last quarter's been up, it's been down, did the same thing this time last year.”
  • Speaking about the costs for the Bakken and Eagle Ford, Conoco stated “Those numbers are very low. That's really not what's driving us. Those, we could drill like crazy right now in both the Bakken and the Eagle Ford and make a lot of money at today's prices. Those have got cost of supplies down in the 30s. But that's not really what's driving us. We don't want to go run out and add rigs too quickly before we get to a clear macro environment that's going to be supportive of that”
  • Conoco stated that they are not in a hurry to add rigs and they are not going to drill into the face of $40 headwinds despite the fact that they can make money off of some of their portfolio at $40/bbl.


On Thursday, July 28, 2016, Shell Executives addressed earnings and made the following key points: 

  • Capital investment is being managed in the range, $25 billion to $30 billion per year through to 2020. This has also improved capital efficiency and developed a more predictable flow of new project. At the end of the second quarter, the rolling average capital investment was $31 billion, including a full four quarters of BG investment. They are firmly on track for the prior guidance of $29 billion this year which is some 38% lower than the pro forma Shell plus BG level back in 2014.
  • By 2018, the start-up since 2014 and the combined portfolio should be producing more than 1 million barrels a day, primarily high margin barrels with cash operating costs around $15 a barrel and a 35% statutory tax rate.
  • Shell expects we will still see total oil demand grow robustly this year. Shell has seen very, very significant increases in gasoline and diesel sales in a lot of markets, particularly China and India.
  • When asked if cost savings were here to stay in light of Schlumberger comments, Shell stated, “[W]ith quite a few service companies, we're also reworking the way we work together. So it is genuine waste elimination, duplication of activities that if you really work very hard together with our on-well site staff and well site staff of service companies, you can find significant ways and means to reduce activity.”


Pioneer Natural Resources CEO Scott Sheffield presented Q2 earnings. Mr. Sheffield made the following points:

  • Improved fracking techniques have helped the companycut production costs in the Permian Basin to nearly $2/bbl, low enough to compete with Saudi Arabia.
  • Excluding taxes, production costs have fallen to $2.25/bbl on horizontal wells in west Texas' Permian Basin, making it on nearly even footing with the lowest-cost producers of conventional oil.
  • "The Permian is going to be the only driver of long-term oil growth in this country. And it's going to grow on up to ~5M bbl/day from 2M," even in a $55/bbl price environment.” However, Mr. Sheffield also said that other U.S. shale plays, notably the Bakken in North Dakota and the Eagle Ford in south Texas, may not be able to weather the downturn as well given their higher costs.
  • Pioneer expects production to grow 15% per year through 2020 after posting Q2 output of 233K boe/day, with most of the growth in the Permian, although it also has acreage in the Eagle Ford.

By: Ty Chapman

Five Star Metals, Inc.

Raising the Bar for Customer Service and Quality

Twitter: @FSM_TY

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