Guest Post courtesy of happy Sentieo client and energy expert Philip Dunham .
2016 was a volatile year for oil and gas. WTI traded to lows in the mid $20s, then rebounded to finish the year around $54. The road to recovery for the energy industry in 2017 can be characterized as cautiously optimistic as WTI prices have stabilized over the past couple of weeks and energy companies have started to slowly hire and ramp activity.
There were a number of themes that emerged as the year progressed including:
- Rebounding rig counts and the return of service cost inflation
- The Dallas Fed and Permian-focused E&Ps expressing concerns over rich Permian Basin acreage valuations
- Another year of low oil prices and OPEC production cuts
- The RINsanity of ethanol blending and a possible border adjustment tax
- Natural gas coming out from the shadow of oil with demand catching up to supply
We will review the themes of 2016 and those themes going forward into 2017.
Oil Field Service Cost Inflation
After the rig count recovery of 2016 and stabilization of oil prices, it is clear that the North American land market has clearly turned the corner. For the oilfield services sector, 2015-2016 was dominated by cost deflation as drillers dramatically reduced activity. The most resilient E&Ps that were able to maintain some level of drilling activity were able to push OFS providers for costs reductions to bring down their economic breakevens.
Now that North American onshore has turned the corner and activity is increasing, we need to monitor for service cost inflation, either from materials like proppant or labor. With a relatively tight labor market and unemployment rate of 4.70%, other industries like construction are competing for the same labor pool. The next couple quarters should begin to reveal whether cost inflation is beginning to bite and what sort of pricing power OFS companies have in early stages of the upswing.
With Doc Search you can set up keyword searches to monitor this. A search for “cost inflation OR price increase” filtered by sector and only transcripts has started to return instances of those keywords on Q4 earnings calls:
As the upcycle begins, growth in E&P investments will be led by the North America land operators who appear to remain unconstrained by years of negative free cash flow, as external funding seems more readily available and the pursuit of shorter-term equity value takes precedence over full-cycle return. E&P spending surveys currently indicate that 2017 North America E&P investments will increase by around 30% led by the Permian Basin, which should lead to both higher activity and a long-overdue recovery in service industry pricing.
There’s been a lot of change in North America over the last few months. Dave shared with you how we used our market share strategy to regain profitability. The next step in boosting profitability is increasing prices, so let me start by talking about where we see pricing. Wild rumors are circulating in the industry about huge price increases. That’s just not a universal fact. Given our position in North America, no one knows more about pricing than we do and here is what I do know.
First, I like talking about price increases more than decreases. It’s a nice change. Second, the service price recovery is starting from an extremely low base; in many cases, below variable cash cost. Third, the level of pricing that satisfies a particular service company depends on where they are on the profitability continuum. And finally, even though the industry is starting at different profitability levels, every company will have to march back up the same path to profitability.
During the downturn, our industry went through a steep regression in profitability as pricing and activity declined. The industry moved from positive operating margins to negative operating margins, then to negative EBITDA and ultimately wound up struggling to cover variable cash costs. It was a fast and hard road that caused a dramatic shift in the landscape of the service industry and wiped out a significant amount of shareholder equity.
The pricing brawl continues as the industry recovers and equipment availability tightens. Pricing at the margin is ultimately set by whoever is satisfied with the lowest returns. It’s important to understand that our competitors’ motivation for margin returns is largely built around where their pricing is anchored today. For example, if they are at negative variable costs, then they are trying to get to a negative EBITDA. If they are at negative EBITDA, then they are trying to get to negative margin and so on.
I can tell you, despite what you hear in the market, it’s clearly a bridge too far to skip from negative variable cash to positive operating margin in one step. So the industry pricing regression I discussed earlier needs to become a pricing progression. This means that for now, Halliburton will have to compete with companies that are satisfied with lower levels of short-term profitability, but we don’t believe their pricing is sustainable. You can’t have negative margins forever. In the meantime, Halliburton will continue to maintain our focus on execution and service quality as we defend our position without sacrificing price. I believe that superior service quality is a prerequisite to having a meaningful pricing discussion and our dedication to service quality helped create the profitable results for the quarter.
However, as we also said previously, the North American shale segment remains a wildcard in all of this. Since details of OPEC’s plans surfaced, rig counts have increased by 33% in the United States with over 170 rigs added and a corresponding increase in US shale production already underway.
Second, we said that commodity prices needed to stabilize for confidence in the customer community to improve and investment to accelerate. We continue to believe that North American operators need sustained prices in the mid to high $50 range for this to occur. The North American shale operators’ ability to rapidly increase production has resulted in commodity price recovery being shallower than expected and bringing uncertainty to the sustainability of these recent price increases.
Third, we said that activity needed to increase meaningfully before access service capacity could be absorbed and pricing recovery could take place. We are seeing the first signs of this in select product lines in a few of the North American basins, but I still believe there remains a fair amount of capacity that must be absorbed before service pricing will become more tightly correlated with higher commodity prices and increased activity. With this backdrop it’s clear the market has taken a positive turn and we have all the elements in play for recovery.
Marc Bianchi, Cowen and Company – Analyst 
Okay. What sort of cost inflation items are you watching? Where do you think we’ll see cost increase first? Any comment on how much those could increase, or have increased?
Andy Hendricks, Patterson-UTI Energy, Inc. – President & CEO 
You know, it’s going to be the traditional cost inflation. The first one and probably the most challenging for the whole industry, not just us, is going to be around labor. In drilling, for instance, we kept the wages at the drilling rigs the same for the position. In pressure pumping we’ve cut back on overtime. We’ve cut back on per diem. It’s just been a more challenged business environment.
And so there is going to be some inflation in labor in pressure pumping. I think everybody is going to have it, not just us. It’s going to be more challenging to recruit.
I think a lot of people don’t realize if you go to Midland, Texas today, even though we’ve been in this downturn for two years, the unemployment rate in Midland, Texas is still lower than the national average. Many of the people that work in the oilfields in West Texas typically rotate in from other cities around Texas or other cities around the US. And if they’ve been gone for six or nine months, they’re starting to get absorbed into their local workforce and may or may not be so interested to come back to work in an oilfield.
As HAL’s Jeff Miller mentioned, service companies like talking about price increases. Unsurprisingly, E&Ps do not. Both sides always have a tendency to talk their book, with service providers emphasizing price increases and E&Ps downplaying them, so it’s worth monitoring the same or similar search but filtered for E&P sector.
While it is likely that a tight labor market will lead to some wage inflation, this needs to be taken in context of the likely trajectory of rig count and drilling activity. Efficiency gains like pad drilling mean that much fewer rigs (and therefore labor) are needed to drill the same amount of wells than a few years ago. Therefore, even if oil prices were to increase enough to warrant substantial increases in activity in the Bakken and other relatively higher cost basins, rig count is not going to return to 2014 levels of around 1500 US oil directed rigs. For example, this comment from Vicki Hollub, CEO of Occidental $OXY on their Q2 2016 earnings call:
We have the capacity to increase significantly. We will be more limited by our disciplined approach, but we certainly have kept the capability within our organization. We have the ability to put the infrastructure in the Permian, so we have, I would say, significant ability.
At one time we were running over 25 rigs and we could, if prices were in the range that would warrant that, we could get back to that. But bearing in mind now that back when we were running 25 rigs, we were not as efficient as we are today. We are significantly improved with our efficiencies so we could get actually the same amount of productivity with half the number of rigs that we were at, at that time.
The Permian Basin:
2016 was the year of the Permian. With stacked pay, existing infrastructure and other advantages, it has been a clear low cost, high return leader. The market finally came around to that view in 2016. I set up a keyword alert in 2015 and it really lit up this past year as capital flowed into the basin as the market saw an increase in oil flowing out despite low prices. This is in contrast to the Eagle Ford and Bakken where production had started to decline.
A production table from the EIA:
Permian, Eagle Ford, Williston and DJ-Niobrara Rig Counts:
Permian deal activity from 2015 and 2016:
As of January 2017, there have been over 30 Midland and Delaware deals since 2015. Deal activity accelerated in 2016, in both Midland and Delaware with the price paid per acre roughly doubling. Already this year, Exxon acquired privately held assets for $6.6B and Noble bought Clayton Williams for $3.2B. (Exxon and Noble Stoke Permian Passions)
Below is a valuation table with all E&Ps and IOCs that have mentioned Permian acreage positions in their most recent filings, with acreage holdings and split between Midland and Delaware sub-basins if disclosed.
However, things may be getting frothy. The Dallas Fed recently published its quarterly energy survey of industry participants. For Q4 2016, special questions about Permian acreage prices were added. Below are some excerpts:
Comments expressing concern over acreage prices:
“The Permian transactions are approaching price multiples associated with a bubble or a Ponzi scheme. Multiple private equity (PE)-backed buyers are simply trading assets from one to the other—very similar to transactions we witnessed in the early ‘80s real estate bubble, the tech bubble of ‘98–‘01 when venture capital firms co-invested with each other to drive up paper gains, and the oil transactions prior to 2014 when every PE fund, pension and endowment manager needed shale in their portfolios.”
Comments mixed on whether current acreage prices are overvalued:
“Stacked plays and improving technology make the Permian Basin very prolific for the production of oil and gas, so relatively high acreage prices are justified. That said, current acreage prices have reached an exuberant level that leaves little protection against extended periods of sub-$60 per barrel oil. Leasing Permian acreage at current acreage prices is not something that we would do.”
“With companies suggesting that as many as 64 wellbores are possible in one section in the Delaware Basin, it is not surprising that acreage prices have skyrocketed. In many cases, this is a multi-decade proposition. To suggest to investors that this is possible is probably acceptable … but to suggest that it is achievable, is, at least, suspicious. There will be a day of reckoning in how high the acreage cost goes. If we stay in the $45–$55 range, then many of these ‘prospects’ will be uneconomic.”
“No. I believe acreage prices are overvalued in certain areas based on speculation on what oil prices may become and what production may be proved in the future from those areas. Some areas prices are justified based on current data, but others are not. This is not atypical for oil and gas investing.”
Permian E&Ps have been noting similar concerns on calls
Parsley Energy ($PE) is a pure play Permian E&P and was very active acquiring assets in the basin the past year or so, making five acquisitions since December of 2015, including a deal for Midland and Delaware assets on January 10th of this year. Using Doc Search for “delaware acreage prices” returns Parsley CEO Bryan Sheffield’s comments from the company’s Q2 2016 earnings call in August of 2016:
John Freeman, Raymond James – Analyst 
And if I shift over it to Delaware, you know, Bryan, you have always been really candid on what you are seeing in sort of the A&D arena, and obviously when we look at the acreage prices. You picked up acreage from the Delaware in the spring and then as recently as last year’s call you sort of said in the Delaware you were seeing acreage prices like $10,000 to $5,000 acre, and obviously last month we’ve seen like a double. I’m just curious from your perspective what you think drove such a huge increase just all of a sudden? Is there anything you can point to in terms of confidence of additional zones, costs or anything like that?
Bryan Sheffield, Parsley Energy Inc – CEO 
I’m still little bit in shock what I’ve seen in the past couple months. I mean we just paid last April came out and you look at April, we paid around $9,000 an acre, and I know some of these sellers, recent transaction sellers, paid about equivalent, about six months ago, or nine months ago, if look at the [Ogder Stevens on his bond], and [as research] you know how much — you can kind of put together what the transaction is and then six months later.
So it’s truly amazing. We’ve gone from $9,000 acre print to a $25,000 acre print and now a $35,000 acre print. I think we’re in the world of $20,000 to $25,000 in the Delaware. I really think that’s the reality. Anything north of $30,000, I think that’s kind of — we can’t get to it on a map in the return on acquisitions.
Looking at Parsley’s January acquisition, if we take the Delaware portion of the deal, which is $205 million for 5,300 net acres, back out 1,100 flowing Boe/d at $40,000/Boe/d, price per acre is roughly at the $30,000/acre ceiling Sheffield mentioned back in August.
Parsley isn’t the only one noting high acreage values.
Anadarko ($APC) Q3 2016 earnings call in November:
Arun Jayaram, JPMorgan – Analyst 
Good morning. Al, I wanted to start a little bit in the Delaware. We saw a pretty punchy evaluation for the Silver Hill asset package in Loving and Winkler with the transaction, I think, fetching more than $40,000 per acre.
I was wondering first if you could remind us of your acreage position in Loving, and if you could discuss your broader delineation efforts beyond the Wolfcamp A because clearly the industry is pretty excited about the stacked pay potential in the Delaware.
Al Walker, Anadarko Petroleum Corporation – Chairman, President and CEO 
Well Arun, thank you. I might have Darrell help me a little bit with some of the questions you ask. But let me just say, as we looked at Silver Hill — and obviously you know the geography quite well, you know they’re quite right next door to us in terms of how their acreage is very close — as I’ve looked at how these acreage values have increasingly gone to places I would never have imagined — I mean, we are paying — or seeing people, rather, pay price per acre today that exceeded acreage values when oil was over 100. And so consequently I think we have a little bit of pause around just the valuations and how certain of these have escalated in places.
EOG’s ($EOG) EVP, Exploration and Production speaking at UBS Houston Energy event in September of 2016:
Unidentified Participant 
Plenty of time for questions. Maybe I’ll start with a quick one (inaudible). You’ve seen so many transactions in the Permian in the last several months. And seemingly, every single one is done at 25,000 per acre or more. And then, the Yates deal, if you make some adjustments, it’s pretty clear that you got the Delaware at less than 10,000 per acre. Could you just give us some background about how that transaction is put together and help us understand how the price can be so attractive?
David W. Trice, EOG Resources, Inc. – EVP, Exploration and Production 
Yes. I think, really, this was a private deal. It was a negotiated deal. The Yates family were — they were very keen on doing a corporate deal and doing a stock deal. And they really wanted EOG stock. And so really, what this transaction represents is — I mean, it really is a merger in the sense that Yates family’s been in business for a very long time. And they’re looking at a longer time horizon. And so they’re wanting to fully maximize the value of their acreage. And they felt that EOG was the very best to do that.
And the reason why we haven’t historically been an acquirer is because typically these transactions are very low rate of return. But this is just one of those situations where the two parties were aligned. Yates family was — in addition to being long-term players, they’re very concerned about their legacy, and they want to be partnered with a good company. So it all came together, and we were able to have kind of a win-win situation there.
But I agree that the transactions that are going on in the basin — I mean, they’re very high-priced. I certainly wouldn’t expect EOG to do any of those kind of deals. Because we don’t really feel like if you’re paying $30,000 or more an acre, it’s going to be very, very hard to get a good all-in rate of return on that.
While others are less concerned.
Scott Sheffield, Pioneer Natural Resources ($PXD) CEO, speaking at Barclays CEO Energy and Power conference in September of 2016:
Also we got lot of questions yesterday about acreage values. Acreage values have moved up to the same price, or higher than they were in 2013 and 2014. I think it shows most companies that are not in the Permian or have to move with the Permian. Most of the Midland Basin has already been bought up. The highest price paid in the Midland Basin recently was [$58,000] per acre. People are generally paying [$40,000 to $45,000] per acre. And then in the Delaware, it’s up to [$37,000] per acre. And so, things are being bid up, simply because there is a lack of inventory. People know that the Permian is very oily and they have to be there long term, especially if you believe in the strip pricing over the next several years. We do say that there is room to make money, but when you pay those prices, because we use a PV-10. When you take a 1 million BOE equivalent well and run it out, it’s worth somewhere between $80,000 and $100,000 per acre. So that’s why people are still paying up to $60,000 per acre. There is still room to make money if you believe in the existing strip price.
So, is the Permian overvalued? Searching transcripts confirms what the Dallas Fed found in their survey. Many Permian focused E&Ps with a long track record in the basin think valuations are at minimum on the rich side. Others seem to be more complacent, but they seem to be in the minority.
Another significant event in 2016 was the landmark OPEC decision to cut production by 1.16MM barrels per day.
Saudi Arabia, Iraq, Kuwait will shoulder 966k barrels per day of the total. Non-OPEC countries agreed to cut by 562k barrels per day, with Russia cutting 300k of that total and other non-OPEC producers like Mexico and other smaller producing countries through natural declines.
The reason OPEC changed strategy from its prior strategy of maintaining market share is for a handful of reasons.
- US Lower 48 production has fallen from a peak of 9 million barrels per day to a trough of 8 million barrels per day in mid-October and has since rebounded to 8,250 barrels per day based on EIA 4-week average of L48 production. OPEC’s market share strategy succeeded in that it forced producers to scale back drilling, especially highly levered producers (some of which have filed for bankruptcy), while others are impaired due to high debt burden and lack of access to capital markets.
- OPEC country fiscal situations are deteriorating due to falling oil revenue. OPEC effectively acknowledged that they have to live with low-cost shale producers in the Permian and other basins that were able to take advantage of cost deflation that lowered break-evens. At the same time, they acknowledged that they too, were feeling the pain of low prices. Especially countries like Venezuela. As far as market impact, the announced cut should serve to set a floor. However, returning production from the Permian as well as the lingering threat of cheating on production quotas serves as another factor helping keep a ceiling on prices, thereby discouraging the over-levered high-yield debt-fueled exuberance of US E&Ps that characterized the shale boom leading up to 2014-2015. While it’s unlikely the deal will fall apart, compliance will have to be monitored. Examining the news flow reveals this headline about record exports from Iraq which sent oil lower and this headline about Saudi Arabia cutting exports to some customers.
One potential wildcard is the Trump and GOP border adjustment tax. See Why OPEC should fear the Trump administration and Trump Tax a Wild Card for Oil for more details. Another potential wildcard is a border wall tax on Mexico- Border Wall Tax on Mexican Crude Oil Would Cost U.S. Drivers.
If either is passed, which seems unlikely at this point because of WTO Rules, it’s very difficult to gauge impact with any reasonable certainty. The only certainty will be extreme volatility in the short term. Goldman Sachs estimated that a border adjustment tax impact could be a move in WTI of $13/bbl immediately and a resulting pass through to gasoline increase of $0.30/gallon. Absent a wild card like the border adjustment tax being passed or political volatility, fiscal stimulus, etc. it’s reasonable to assume oil prices will remain range bound in the mid-high $50s to high $40s. That said, political risk to markets going forward is much higher than on November 8th.
President Trump has made very clear that he is not a fan of regulation, with particular ire directed at the EPA and the Renewable Fuel Standard (RFS). A detailed look at the RFS and problems with it are beyond the scope of this post, but you can read more here. Trump advisor and refinery owner Carl Icahn has been very vocal as well. Basically, the RFS requires that refiners blend a biofuel, either ethanol or biodiesel, into every gallon of fuel produced and sold in the US (exports are exempt). Or, refiners can buy a RIN instead. RINs are generated with every gallon of biofuel produced. These can then be sold to refiners that choose not to blend biofuel. Prices can be volatile (What caused the run-up in ethanol RIN prices during early 2013?) which makes compliance for refiners without blending capability expensive as RIN prices rise. One of the problems with the RFS mandate is the “blend wall”: a practical limit beyond which refiners say the amount of ethanol in a gallon of gasoline will begin to damage engines. You can read more about the blend wall here. Using Doc Search with the query “RIN OR “blend wall”” and Plotter, we can see a clear trend of mentions in 2013 and 2016.
Given President Trump’s statements and GOP majority in both House and Senate, it seems very likely that RFS will be at minimum changed to relieve the burden on refiners like Icahn’s $CVI. As I mentioned above, a potential wild card for oil and gas (and any company or industry that imports substantial amounts of goods) is the border adjustment tax. It was mentioned on Q4 2016 earnings calls of Exxon($XOM), Marathon($MPC) and Valero($VLO). But it’s not just oil refiners that are discussing the potential tax, GM, UPS, AT&T, Domino’s have all mentioned it so far this year. It’s probably a good idea to save a border adjustment tax search on all public companies to be aware of potential winners and losers if the tax becomes law.
The oil glut of the past few years has overshadowed the natural gas market. 2017 should bring it out from the shadows. In 2016, natural gas production is expected to decline 1.3 Bcf/day to 77.5 Bcf/d from 2015 levels (EIA STEO). It marks the first annual decline since 2005, which was the year just before the advent of fracking kicked off the shale gas boom. Because natural gas can only be transported by pipeline and it takes time to build power plants and incentivize industrial consumers to build natural gas-fed plants, demand is much less elastic than shale gas supply. This has led to a protracted glut that first emerged around 2009-2010. 2017 demand is expected to bring the market more into balance as domestic demand is expected to increase, together with exports to Mexico increasing and LNG exports ramping up as Cheniere brings its third and fourth liquefaction trains online. While the demand outlook is improving, we still need to watch a few things:
- How quickly gas producers increase rig count in response to higher prices.
- The associated gas coming out of the Permian.
- The emerging SCOOP/STACK play in Oklahoma which produces oil and liquids-rich natural gas. It’s worth remembering how associated gas from the Eagle Ford and other liquids-rich gas plays exacerbated the gas supply glut. How much of an impact it may have on gas supply is difficult to say for sure at this point, but something to keep in mind.
With North American drilling activity turning the corner and on the upswing, OPEC, and natural gas supply/demand balance, 2017 certainly won’t be boring for oil and gas.
Full disclosure: I, Philip Dunham, am the primary author of this article, and it expresses my own opinions. I am not receiving compensation for it. I have no business relationship with any company whose stock is mentioned in this article, beyond trading small numbers of shares of Parsley Energy, Inc. in the normal course of my trading activities. The information and data presented in this article were obtained from company documents and/or sources believed to be reliable, but have not been independently verified. Therefore, neither Sentieo nor I can guarantee their accuracy. Please do your own research and contact a qualified investment advisor before making any investment decisions. Neither Sentieo nor I are responsible for investment decisions you make.