We hope everyone survived this past week’s Arctic freeze. Crazy weather. Tonight’s note is relatively brief. A quick update on this week’s conference plus a few observations from several Q4 earnings calls.
THRIVE Energy Conference Update. We were attacked this past Saturday by internet gremlins. Somehow LinkedIn announced our conference was cancelled. Liars, I say. Frankly, we have purchased too much beer and Flecha Azul tequila that there’s no way we are cancelling. In fact, we are so pumped for this week, we are already looking forward to next year’s event, so go ahead and save the dates as we expect to return to Minute Maid Park on February 22-24, 2022. As for this week’s event, we just went over 800 registrations with a fairly large surge on Friday with more trickling in over the weekend. Registration now stands at 816 from 350 companies. We will, however, stop registration at the end of business on Monday as we are nearing capacity. That said, there are still a bunch of you who haven’t registered, including some sponsors. Our readership audience is largely executives and we know you are busy, but please fill out the registration link if you intend to show up. Lastly, conference attire is business casual because I hate ties.
Thrive Energy Registration Link
Q4 Earnings observations. Several prominent names pushed Q4 earnings due to the horrendous weather. Makes sense given the need for time to digest the harsh realities of lost work and shut-in production. For those who did report, we offer a few big picture takeaways as well as a few company specific anecdotes. Notably, the E&P messaging is consistent: (1) focus on free cash flow; (2) ESG, notably efforts to cut emissions; (3) strong returns driven by improving efficiencies and low service costs. On point #1, all reporting companies cite their respect reinvestment ratios which generally come in around ~70% of discretionary cash flow (DVN = 70-80%; CLR = 65-75%; SM <75% beginning in 2022). On point #2, ESG metrics are increasingly being tied to long-term incentive compensation, highlighted by DVN, EQT, SM, OVV and CLR. We’ll have to read the proxy statements for details, but public E&P’s are listening to investor demands. On point #3, virtually all E&P’s highlight the continued improvements in well productivity and record low D&C well costs. In the case of DVN, it implemented a variable dividend while for most others, FCF generation/debt reduction efforts in 2020 were stout. Broadly speaking, the E&P space is doing well. As for the service calls, quite a different story as companies are barely generating positive EBITDA.
EQT: 2021 capex budget = $1.1B to $1.2B. Roughly $800-$850M will be upstream directed. 2021 activity calls for an average of 2-3 frac spreads and 1-2 HZ rigs. A total of 84 HZ net wells will be drilled vs. 28 in Q4 (or 112 annualized) while 98 net wells will be completed vs. 19 in Q4 or 76 annualized. Average HZ lateral lengths expected to average ~12,900 feet on wells drilled. The company has now fully transitioned to electric frac fleets while it also employs hybrid drilling rigs. These initiatives, among others, are components in EQT’s drive to reduce GHG emissions intensity by 4% in 2021. Beyond its ESG focus, EQT has made remarkable strides cutting costs under new management while also adding strategic acreage to the portfolio. Debt reduction remains a priority with EQT calling for $500-$600M of FCF which presumably goes primarily to balance sheet enhancement. The company’s net debt declined by ~$400M in 2020 and is expected to decline another ~$400M in 2021. Debt reduction will likely extend into 2022. But what got our attention was a comment made during the Q&A session on the call. We will paraphrase a tad here, but the company stated “when you step back and you realize that in Appalachia we’ve got 30 teams running 30 rigs, you may have 30 efficient companies but when you look at that, it could be more efficient” That’s a pretty powerful statement and applies to both E&P and OFS. Moreover, the comment implies the obvious which is you don’t need ~30 G&A structures to run such small programs. Whether or not the company’s unit/company counts are precise is not important. Rather, it’s the recognition businesses can be run better. Management wisely took this comment one step further noting the low utilization of service companies and less-than-optimized gathering systems. Essentially, all of these enterprises would benefit from consolidation to maximize utilization and in our opinion, allow for more cost savings.
SM: 2021 capex budget set at $650-$675M vs. $540M in 2020. Q4’20 capex = $137M or $548M annualized. Q1’21 capex = $180M or roughly ~27% of the 2021 expected spend. SM will complete 93 net wells in 2021 vs. 77 net well completions in 2020 (+21%). Roughly 70% of the 2021 budget will go towards the Midland Basin with the remaining 30% directed to South Texas. While no formal 2022 budget was announced, a graphic in the company’s slide deck suggests 2022 capex could be in the $550M vicinity as SM moderates its reinvestment rate. In prior notes, we touched on the role of hedges and how that could limit spending. In the case of SM, roughly 75-80% of its 2021 oil production is hedged at $41.37/bbl. In the Midland Basin, SM is running three rigs and three frac crews. The DC&E costs are expected to average $520/lateral foot. That’s impressive. Operational highlights include a 54% improvement in drilling feet per day (from 2017 to 2020) and a 165% improvement in completed lateral feet per day (now at 2,019ft). Lateral lengths also moved higher, averaging 11,420’ in 2020 vs. 9,300’ in 2017. In South Texas, SM is running one rig and one frac crew. Average laterals to be ~12,000’. Total net wells drilled in 2020 (both Permian/STX) were 98 vs. an expectation for 94 wells in 2021. 2021 budget appears somewhat front-end loaded.
OIS: Revenue = $137M, +2% q/q. Adjusted Q4 EBITDA = $2.2M vs. $400k in Q3. Revenue growth will lag most SMID OFS given the Offshore Products segment which is a later cycle business. Balance sheet enhancement remains a core goal and accomplishment for OIS as it reduced total net debt by $128M in 2020, yielding a net debt/capitalization ratio of ~13%. Net debt/’21 EBITDA (per OIS guidance) is closer to 3x, thus it’s reasonable to see OIS continue its focus on FCF for debt reduction purposes. To that point, OIS’ capex budget for 2021 is $15M, essentially the same as 2020. Outlook is improving as Offshore Products should see its book-to-bill approach 1x this year. Also, while Q1 will be burdened by weather gremlins, activity and profitability will move higher in Q2. Like other OFS enterprises, OIS is evaluating opportunity sets to play in the alternative industry space, namely using its expertise in platforms to potentially win work with offshore wind farms. Management was careful to note this opportunity set will not develop overnight. With the core business, OIS continues to streamline costs as the focus on generating strong incrementals on the upside is paramount. During Q4, OIS incurred another $4.3M on non-cash fixed asset and lease impairment charges (due to facility consolidations/closures) and $2.7M in severance costs.
CLR: 2021 capex budget = $1.4B, of which $1.1B will be allocated to D&C activity. D&C spend in 2020 totaled $971M while in Q4, CLR spent $151M. Thus the 2021 D&C spend represents a sharp uptick relative to the Q4’20 annualized spend. The company will average 11 rigs in 2021 which includes the addition of two rigs to CLR’s Northern operations (i.e. PRB with 2 rigs deployed in Q2). The company will run 5-6 rigs in the Bakken and 4 rigs in Oklahoma. FCF at $52 oil is expected to be near $1.0B which will be used for debt reduction and shareholder returns (CLR reduced Senior Notes by $539M in 2020).
NEX: Revenue = $215M, +31% q/q. Adjusted EBITDA = $8M vs. negative $2M in Q3. Total fleets deployed in Q4 = 17 with 14 fully utilized fleets. This compare to 13 fleets deployed in Q3 and 11 fully-utilized. Annualized gross profit per fully utilized fleet = $6.2M vs. $5.5M in Q3. If one were to normalize, which we believe should be annualized gross profit per active fleet, the gross profit per fleet would decline to $5.1M. One interesting observation, NEX noted white space burdened Q4 results. If each fleet had two additional working days/month, the company’s consolidated EBITDA would have nearly doubled. This is the value of good utilization. Outlook: NEX expects Q1 revenue to be up 5-10% q/q with 18 active fleets and 15 fully-utilized fleets. Beyond Q1, NEX sees another 2-3 spreads going to work in Q2. Capex will run $3M per fleet or ~$54M under a ~20 fleet scenario, plus $3M for other NEX service lines and ~$25-$30M for the company’s ESG strategy (i.e. Tier 4 DGB and Power Solutions). Ballpark this looks like a 2021 spend somewhere in the $100-$125M which compares to $124M spent in 2020 and $13M spent in Q4. Management believes there are 165 fleets in the market today – not clear to us if they are referring to active or fully-utilized. We view the frac world through the lens of active fleets which we peg closer to 190. One of the striking comments was management’s expectation that some long-term customers expect to “add meaningful activity” through the year. This was not quantified, but is noteworthy as NEX has historically worked with several Tier 1 E&P’s.
DVN: The company’s 2021 upstream capex budget is set at $1.6B to $1.8B. DVN spent $183M in Q4 while WPX spent $283M, thus $466M total or $1.9B annualized. The company will average 18 rigs in 2021, with 13 in the Delaware. Targeted reinvestment ratio is 70-80% with free cash flow going towards DVN’s variable dividend program, followed by debt reduction. Like EQT above, we found some of DVN’s comments fairly striking. In particular, DVN’s CEO stated it has “no intentions of adding any growth projects until demand fundamentals recover, inventory overhangs clear up and OPEC+ curtailed volumes are effectively absorbed by the world markets. Importantly, I encourage other producers to be very thoughtful and disciplined when it comes to capital plans”. That’s fairly strong signaling and earnings calls to date would suggest the public E&P universe is largely on board. We doubt private E&P’s with access to capital will do the same. Now contrast the DVN comments to the service sector which has seen management teams claim they won’t reactivate equipment until prices go up. We wonder what would happen if an OFS leader took this one step further and said their company was raising prices and they encouraged other OFS companies to do the same? Back to DVN’s capital plans, it will also bring 320-360 wells on line in 2021; ~80% of the upstream budget will be dedicated to the Delaware; LOE costs are expected to decline ~4% y/y in 2021. In the Eagle Ford, DVN will complete 22 DUCs in 1H’21 while it will bring online 15-20 wells in 2021. 2021 budget appears somewhat front-end loaded.
OVV: 2021 capex budget = $1.5B vs. $1.74B in 2020. Q4’20 capex = $343M or $1.4B annualized. Permian: Averaged 3 rigs in Q4’20 and expects to average 3 rigs in 2021. It will run 1-2 frac crews with 95% of completions being simulfracs. Anadarko. Averaged 2 rigs in Q4’20 with plans to average 2 rigs in 2021. Will run 1-2 frac crews with 75% of work being simulfracs along with continued use of wet sand. Well cost reductions in both the Permian and Anadarko are impressive with pacesetter well costs far below the Q4 averages. Completed feet/day from simulfrac operations was 4,400 feet per day for the record well in the Permian while in the Andarko, OVV averaged 2,700 feet/day. The company’s stated capital program for 2021 reflects a 60% reinvestment rate vs. the framework of 75%, a function of higher oil prices. FCF in 2021 is expected to be nearly $1B which will go towards debt reduction.
CRK: 2021 capex budget = $510-$550M vs. $484M in 2020. Q4’20 capex = $169M or $676M, thus rate of spend/activity will moderate. Notably, CRK is running 6 rigs today, but plans to reduce to 5 rigs in May. The company is running 3 frac crews now, but plans to average 2.2 crews in 2021. The reason for less rigs is a function of drilling efficiencies. Company, like others, is focused on FCF and expects to generate $200M of FCF in 2021. This will go towards debt reduction. During 2020, CRK drilled 46 net wells. It will drill 51 net wells in 2021. During Q4, the company drilled and completed its longest lateral which came in at 12,716 feet. It is working on one now that is 13,000 feet. Proppant loadings have increased to 3,500 pounds per foot, up from 2,800 in Q2/Q3.
Other: Earlier this week Ingersoll Rand sold ~55% of its High Pressure Solutions segment (i.e. Gardner Denver) business to American Industrial Partners (“AIP”) for $300M in cash. Previously, AIP had acquired ValTek (via Serva Group) in August 2020. With CAT’s purchase of Weir’s pump business and now what could be viewed as a consolidation of Gardner Denver/ValTek, we are starting to the power end/fluid market come together. We have not had time to dig into the Gardner/AIP transaction, so we are somewhat short of details. That said, when one considers the changing customer base (i.e. LBRT/SLB which will presumably standardize on ST9) and the prospects for much needed M&A activity amongst frac participants, one would think OEMs and service providers should be paying attention, thus arguably scale matters. We will probe this deal and its implications at our conference this week and will touch on it next Sunday.
Upcoming DEP Events:
April 1st – DEP One-Year Anniversary Social (DEP Office)
April 7th – Kingwood Semi-Annual Golf Outing
May 26th – Whistling Straits Energy Forum (sold out)
June 15 – London Energy Day (TBD based on COVID travel restrictions)
June 30th – Telluride Executive Series
July 15th – OKC Steak & Baseball Outing
August 11th – Pittsburgh Truck Tour & Pirates Game
August 30th – European Energy & Industrials Conference
September 30th – Permian Basin BBQ Cook-Off