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August 9, 2018

Heard on The Call: Bonanza Creek Energy

Bonanza Creek Energy is presenting at the EnerCom Conference on Wednesday, August 22nd in Denver.

Bonanza Creek Energy Inc. reported Q2 results today and elaborated on its DJ Basin operations during the company’s Q2 2018 earnings call held August 9. Excerpts from the call are below.

  • Second quarter sales volumes averaged 18.0 MBoe per day including the negative effects of a prior-period adjustment of 0.6 Mboe per day related to non-operated wells
  • Rapidly improving well performance yields over 1,000 economic drilling locations in Wattenberg
  • Well head pressures effectively managed via Rocky Mountain Infrastructure’s (“RMI”) multiple third-party gas processing optionality
  • Second quarter GAAP net income of $4.9 million, or $0.24 per diluted share; Adjusted net income(1)of $24.2 million, or $1.18 per diluted share

Q: My question has to do to a 1,000 locations you guys have talked about and I think this is the first time you actually openly speak about. Firstly, are those net locations? And then secondarily, could you give us a little insight as to what that would translate into if you were to be drilling more extended reach laterals?

Bonanza Creek President and CEO Eric Greager: It is the first time we’ve indicated because we needed to complete the resource assessment that we started when I first came on-board in April. And that resource assessment, if you’ve been through these before, it starts with that fundamental understanding of the resource itself.

As you work your way through the resource across the acreage position, combine it with what you understand about spacing, stacking, stimulation design, and the latest application of well performance initiatives, you roll all of that together and that has yielded the 1,000-plus locations. They are – and I want to point out, we’ve stated in our press release and elsewhere, these are SRL equivalents. That’s our measure to keep things clear on that.

And the other point of clarification, I think, I need to make is that they are gross locations and that provides some opportunity for us as we continue to develop the resource and continue to drive and apply more cutting-edge subsurface engineering and development. There’s an opportunity to continue to grow this, but I wanted to qualify, A, they’re gross; and B, they are SRL equivalents.

Q: What is the net equivalent?

President and CEO Eric Greager: Because these are SRL equivalents, I don’t know that we have released the net working interest on all of those leases, Irene. We’re going to take a little bit more time and continue working on that. But it’s – our working interest is large on much of our contiguous acreage and all of these wells are sticked in our contiguous acreage, meaning we didn’t stick up scattered acreage that kind of sat at all by itself.

So, there is upside potential with additional acreage that will be sticked up. We wanted to stick with the more contiguous acreage position, one, because we better understand the continuous resource potential; and two, because we wanted to get this information out as quickly as possible.

Q: Of these locations, how many are Niobraras? And do you have some Codells in there and maybe a little bit on spacing and EURs?

President and CEO Eric Greager: Yeah. It’s – I think EURs are kind of in the same space as net working interest although we’ll be able to guide on net working interest relatively quickly. EURs is something that evolves over time, and that’s something that you can expect to get periodic guidance on. I think what we intend to do going forward here is when we finish our assessment throughout 2018 for the well performance and we move into our budget season for 2019, we’ll begin to lean in and start providing our type curves to help model the business and the programs for 2019. And then each year, you can expect to get new type curves that indicate our best guess. But the thing about given EURs and type curve performance for the longer run is it – it fails really to recognize the upside potential that we continue to drive into the business. And I think there’s a significant amount of upside potential yet to come in terms of how we intend to develop our resource over time.

Q:  And also the split between Niobrara and Codell?

President and CEO Eric Greager: Yeah. I think you can look at the Niobrara and Codell. You can look back on our current distribution between Niobrara and Codell and that’s going to represent itself largely proportionately going forward. So, if it turns out to be a typical 6-well pad for example has 1 Codell and 5 Niobrara and perhaps 2 benches, then I think you can expect that same distribution over time. But the thing that you got to keep in mind is, we’re going to continue to optimize every pad going forward with the very best information we have in terms of spacing, stacking and stimulation design, and the interdependencies of those. And I think what you’ll see in the well performance that we’re releasing this quarter is even in a period as short as a quarter, you can create some substantial uplift in well performance, and we certainly don’t anticipate that growth slowing down over time.

The Oil and Gas Conference®

Bonanza Creek Energy Inc. is presenting at EnerCom’s The Oil & Gas Conference® at the Denver Downtown Westin Hotel, Denver, Colo. Aug. 19-22, 2018. EnerCom expects to have more than 80 presenting oil and gas companies and more than 2000 financial professionals attending this year’s conference.

To learn more about the conference and presenter schedule please visit the conference website here.

August 7, 2018

Carrizo Oil & Gas Inc. (NASDAQ: CRZO) elaborates on current operations and Q2 earnings. The Excerpts from the Q2 Call are below.

Q: Eagle Ford continues to look like you’re having really nice success there. Can you just talk about space in a little bit more there? I know you’ve been able to down space a bit with the Brown Trust and others, but just any comments you could have around how you view the rest of your space and field?

President and Chief Executive Officer S.P. “Chip” Johnson: I think generally we’re sticking with 330-foot spacing in bulk of the acreage. There’s still a couple of places we think 500 feet might be better on the Brown Trust. We did have some of the wells in 250 feet. And so far we haven’t seen any interference or better or worse performance, but we’re still in the early six-month period where everything is on restricted chokes and constrained rate. So it’s hard to tell. I think we’d rather just say 330-foot is the easy answer and we’ll keep trying to figure out ways to tighten that up.

Q: Secondly, Chip, there seemed to be a little confusion or maybe just talk a little bit about the Brown Trust accelerated payout. Is that sort of typical of what you’re seeing on a lot of your plays? And again, I mean, frankly I was glad to see it, but I just – if you could talk maybe a bit more about that?

President and Chief Executive Officer S.P. “Chip” Johnson: Well, I don’t think we have back-ins after payout anywhere else in our inventory. We used to – we bought out some of those partners three or four years ago. But this was an arrangement we got into with a major where we had at least half the minerals, they own the other half, and we made a deal with them eight years ago where we could drill and they could either participate or they could back-in after payout. And sometimes they participate, sometimes they back in.

This time, they’re going to back in. And this had been in the fourth quarter. We probably would have had to draw attention to it. But if it had just been in the middle of the year, it wouldn’t have made much difference. But they have 1,000 barrel a day drop in production in the fourth quarter. We felt like we needed to point that out. Otherwise, we thought this would have happened in the first or second quarter of next year.

Q: When that just balances, I guess that’s just sort of a onetime item then, correct?

President and Chief Executive Officer S.P. “Chip” Johnson: On those wells. Next year when we bring on more wells in the Brown Trust, if that company has not participated, then it’ll start another back-in after payout on those wells.

The good thing was we made that much more EBITDA this year than we expected to, because of the raise in the oil prices. So, we felt like it was a good thing.

Q: Just wanted to follow up a little bit on what you’d said there on the Permian and, clearly, you guys were talking about lower activity as you work later this year. But I guess just from a high level, should we expect Permian to continue to grow in the third quarter and then also in the fourth quarter or do you start to see Permian flatten out or even decline a little late this year in terms of the production there? And then into the first half of 2019, just a similar question, does Permian grow? Does it flatten? Does it decline? How do you see that playing out with the activity shift?

Vice President of Investor Relations Jeff P. Hayden: So, if you think about it, you just kind of add on a little bit in some of those questions about activity. What you probably see just given the drilling activity in Eagle Ford this year, and then in fact we’re keeping four rigs there for the first half of next year, I think it’s safe to assume that you probably see the completion activity weighted to the Eagle Ford in the first half of the year. And then it’ll probably be weighted a little more towards Permian in the back half of the year. Given that, what you’re probably going to looking at in the Permian is kind of a flattening. I don’t know if you’ll necessarily see a decline, but maybe a flattening of production over the next several quarters. And then as you get kind of later next year, you probably see the Permian start to incline a lot more as we start increasing the completion activity out there.

In the meantime, I think, between now and then you’re going to see a lot of production growth likely in the Eagle Ford Shale as we kind of shift our activity over there.

Q: I guess is it safe to assume that the changes you guys have made, a shift in capital to Permian that basically all your Permian acreage as you’re looking to protect will get held over the next year here?

President and Chief Executive Officer S.P. “Chip” Johnson: We’ve got a drilling schedule in the Permian that takes care of our acreage. That’s still something – that’s the most critical thing we have to do at this point.

Q: Okay. Now that makes sense for sure. And I guess just lastly on the asset sale that you guys had just mentioned here. Just trying to get a sense in terms of magnitude, if you guys could let us know what the proceeds are and is this a one-off deal or might you guys monetize other little bits and pieces of the Permian going forward?

President and Chief Executive Officer S.P. “Chip” Johnson: Well, I guess in the past we’ve actually sold some little bits and pieces. This one, especially because it was non-op and the new owner, the new operator of these assets was pretty aggressive about capital spending. We felt like this could reduce our non-op CapEx budget significantly over the next two years and we felt like we got a good price for it. Part of our CapEx increase this year has been non-op. We have some other non-op partners who ramped up their activity in different parts of the core of the Delaware Basin and so we’ve had to increase our CapEx for that. But we felt like this was a good chance to maybe get out of some non-op at a good price and reduce that exposure to somebody else’s capital footprint.

August 2, 2018

Nabors Industries (NYSE: NBR) held its Q2 conference call today; excerpts from the Q & A are below:

Q: Tony, you mentioned that your latest survey has another 30 to 40 rigs being added to the rest of this year. And I would tell you, consensus from most investors that I’ve spoken with, is that we’re going to see a meaningful fall off in the Permian, maybe as much as 75 rigs. And so, overall, U.S. rig count is going to suffer modestly. So, this is a very different opinion. Obviously, I assume you’re closer to the customer than most of my – investors I’ve talked to. Give us more color on these rigs. Or are we going to see a decline in the Permian, or does the Permian stay flat and you add in the Eagle Ford and other areas? Just help us understand where that’s going.

Chairman, President and Chief Executive Officer Anthony G. Petrello: Sure. I hate to be the guy in the outlier here. So that’s the reason why we did these surveys because this information doesn’t come from me, it comes from the customers and that’s what the customers told us. Now, I know it runs a little counter to the major concern regarding the differentials in West Texas. So, that led us to go back and we just did this past 48 hours.

We went back to the top 20 operators in the Permian, and we asked them specifically about their limitation for pipeline access. And while our information may not be perfect, it suggested that only 2 of

During the Q2 conference calls this week, some enlightening comments were made by oil and gas company CEOs.

Chesapeake Energy (NYSE:CHK) CEO Doug Lawler examines 2019 goals

Q: Can you talk about 2019 and what the broad parameters of how that is going to look. It sounds like you guys are planning to stop the outspending versus cash flow and now spend within cash flow. And is that the right read on 2019? And what’s the kind of commodity price at which we should think about that being a valid read? And how are you – I know it’s early, but how are you projecting oil volumes to grow and your overall volumes to grow?

Chesapeake Energy CEO Robert Douglas Lawler: Sure, We’re happy to provide a little more clarity with that. And as we’ve stated, we anticipate our 2019 oil volumes to grow by 10% and this recognition of our ability with the remaining assets post Utica divestiture of being able to replace that EBITDA within a year speaks to the capital efficiency and the cash flow generating capability of our assets.

As we look forward to 2019, the reduction in our interest expense, it will help us as we pay down some of our debt. But we anticipate that that free cash flow neutrality is – as a primary target will be something that we have to continue to look at. And as noted, in 2019, we aren’t forecasting any major asset sales. But through our own operations from our existing assets, we expect that production growth will help us in reducing any outspend.

Nick’s point on the sustainable free cash flow at this point and you look to 2019, we will accomplish that principally through our organic production growth, but we will also have and continue to look at smaller asset sales and other opportunities for us to generate cash.

What we’re excited about is that, as I noted, each of the assets are free cash flow positive today, with the exception of the Powder, and the oil’s growth, strength there, we clearly will achieve that in 2020, but targeting with the team to try to achieve that in 2019.

So, our objective to be free cash flow positive is very strong. And from an operating cash flow basis, we’re there. When you look at all the other corporate liabilities that we have, we’re making excellent progress on that and expect to share good results with you as we progress.

Anadarko Petroleum (NYSE: APC) – Delware goal is $8 million per well, DJ is $3 million

Q: What are your current well costs in each basin for the second quarter? What was your AFE or spending in Delaware and DJ?

Executive Vice President of U.S. Onshore Operations Daniel E. Brown: So, from a Delaware standpoint, we’ve communicated previously we’ve got around $8 million is what we expect per copy once we’re in the development mode. We’re higher than that now, as we’ve communicated. It’s closer to $10 million. As we think about DJ, it’s I’d say sort of tilted to $3 million but it depends on the lateral length. And so, the longer wells obviously cost you more, the shorter wells are a little bit less. But think of it as around $3 million.

Q: As you go into 2019, does the Gulf of Mexico pick up a little bit more relative capital versus the onshore business?

Chairman, President and Chief Executive Officer Robert A. Walker: I’d say it’s more of a steady state, but if the options are such that we feel like we want to change that, we can, picking up a spot rig is not particularly difficult. So, I wouldn’t read too much into the implied rig schedule suggesting activity. But I think for us, Gulf of Mexico is two things, it’s more of a steady-state environment that throws off a lot of free cash flow, and that’s real attractive. And if you’re right, we see a tremendous price differential between WTI, LLS, and Brent, where the waterborne has a tremendous advantage, it’s just going to throw off more free cash flow. And I think that’s really the state that we see ourselves in.

Q: At least on our numbers, we’re pretty much in line with strip for the next three or four years, I guess. We still see substantial free cash if you maintain, which I expect you will, your capital discipline. Also, the $1 billion increase in the buyback is terrific. But how do you think about that going forward? It seems to me that you could reload that for a pretty much an extended period. And I’ll leave it there. Thanks.

Chairman, President and Chief Executive Officer Robert A. Walker: Yeah, I think you’re seeing it consistent with the way we see it and hopefully we’re both right. But we definitely believe the approach we’re taking today has tremendous durability. So, we don’t see it as something that’s just very temporary. Obviously, if oil backs up to $40, we’re going to be in a situation like many where we’re going to rethink what we want to do with our capital investments. But in a $50-plus environment and we’re throwing off a lot of free cash flow, there’s tremendous durability to buying back stock, retiring debt, and periodically looking at increasing our dividend which we think, coupled with the attractive growth that we can throw off at $50 as the steady state, is a pretty good business model.

Q: In the Delaware, can you take us through the next year in terms of how you expect your productivity and efficiency to evolve? Specifically, what your expectations are for the percent of your overall rig fleet drilling the multi-well pads, where you think lateral length can go, any shifts in completion methodology? And then you highlighted the goal of $8 million well costs from $10 million. When do you expect to achieve that?

Executive Vice President of U.S. Onshore Operations Daniel E. Brown: Thanks for the question. I’ll try to address them and if I miss one along the way, just remind me afterwards. Obviously, from a – since you’re talking about over the course of the next year or so, clearly our capital plans for 2019 we’ll be talking about in more detail in the fourth quarter. So, I won’t go into too much detail there. But from a general standpoint, we have been, we’ve been working our gen two completions which are, essentially, like some others in the industry, higher water content, higher proppant, closer spacing. We’ve been pleased with the performance we see there. I anticipate that that will be our completion style as we move through certainly the foreseeable future. Our pad development has been, I would say, hovering around 50% currently for 2018. But I’ll say the pads we’ve been able to do aren’t – that’s more than one well. And so, some of these pads are only two-well pads which gets us some efficiency, but not the significant efficiency increases we would expect to see as we get to really substantial multi-well pads which is what we’re looking forward to doing. So, four or five wells per pad is obviously going to be much more efficient for us as we go to two.

So, as we look forward from here, we should see the amount of wells that we’re drilling on pad increase, and the actual wells per pad to increase, both of which will then drive increasing efficiency through the system. So, that’s what I’d say on that. Hopefully I got everything.

Q – Yeah. All but maybe the one, which is that $8 million well cost goal. When would you expect to achieve that?

Executive Vice President of U.S. Onshore Operations Daniel E. Brown: Yeah. So, we’re currently thinking over the course of – as we get to our multi-well pad developments where we’re doing four to five wells per pad, that’s what we’re anticipating. We think over the course of the next, say, two or three years we should be transitioning over where substantially all of our development is sort of in that kind of place. And so that’s how we’d expect that to work over time. So, once we’re doing four to five wells per pad, that’s the type of well costs you should see and we think that transition is going to take place over the next few years.

April 20, 2018

  • Orders of $5.2 billion for the quarter, down 8% sequentially and up 9% year-over-year on a combined business basis*
  • Revenue of $5.4 billion for the quarter, down 7% sequentially and up 1% year-over-year on a combined business basis
  • GAAP operating loss of $41 million for the quarter, decreased 63% sequentially and increased unfavorably year-over-year on a combined business basis
  • Adjusted operating income (a non-GAAP measure) of $228 million for the quarter, down 20% sequentially and down 19% year-over-year on a combined business basis
  • GAAP diluted earnings per share of $0.17 for the quarter which included $(0.08) per share of adjusting items. Adjusted diluted earnings per share (a non-GAAP measure) were $0.09.
  • Cash flows generated from operating activities were $294 million for the quarter. Free cash flow (a non-GAAP measure) for the quarter was $226 million. Included in free cash flow is a cash usage of $100 million relating to restructuring and merger-related payments.

Baker Hughes, a GE company (ticker: BHGE), announced Q1 results today.

The company reported delivering $5.2 billion in orders and receiving $5.4 billion in revenue. “As expected, we saw growth in our shorter-cycle businesses and declines in our longer-cycle businesses versus the previous year.  Adjusted operating income* in the quarter was $228 million. Free cash flow* was $226 million,” the company reported.

“The gas market continues to grow, and strong LNG demand supports the view that new capacity will be required in the early to mid-part of the next decade,” said Lorenzo Simonelli, BHGE chairman and chief executive officer.

“In our Oilfield Services (OFS) segment, we continue to focus on growing share in key markets, including North America and the Middle East, through leading technology and services and flawless execution for customers. This quarter, we secured several critical commercial wins, and our synergy efforts led to improved margin rates.”


March 16, 2018

Erin Energy Corporation (ticker: ERN) announced unaudited financial and operational results for the year ended December 31, 2017.

Full year 2017 revenues were $101.2 million, increasing by approximately 30% from $77.8 million in 2016. Fourth quarter 2017, revenues were $21.7 million compared to $21.1 million for the same period in 2016.

Erin Energy reported a net loss of $151.9 million or a loss of $(0.71) per share for full year 2017 compared with a net loss of $142.4 million or a loss of $(0.67) per share for full year 2016.

Exploration expenses totaled $4.6 million for the full year. As of December 31, 2017 cash, cash equivalents and restricted cash were approximately $33.8 million.

Highlights from 2017

  • Crude sales volumes of more than 1.8 million net barrels of oil;
  • $101.2 million in revenue, a 30% increase over 2016;
  • Total production of approximately 1.7 million net barrels of oil;
  • Spudded successful Miocene exploration well in offshore Nigeria.


Stated in the company’s press release, the average net daily production for full year 2017 was approximately 4,900 BOPD compared to approximately 4,800 BOPD for full year 2016. For Q4 2017, net daily production was approximately 4,000 BOPD compared with 5,800 BOPD for the comparative period in 2016. The average price received for 2017 was $54.84 per barrel compared to $45.45 in 2016.

Net production volumes for full year 2017 were approximately 1.7 million net barrels of oil compared to approximately 1.8 million net barrels in 2016. Erin Energy’s crude oil inventory was approximately $3.6 million at December 31, 2017.

ERN announced early this year that it had successfully completed the drilling of the Oyo-NW exploration well, which discovered hydrocarbons in the Miocene Formation. The well is located approximately 9.5 kilometers northwest of the Oyo Central field on ERN’s offshore Nigeria block 120.

Oyo-NW was drilled to a total vertical depth subsea of 12,218 feet and penetrated multiple sand units with total gross thickness of 260 feet in the depth range from 7,052 – 10,873 feet TVDSS. These values were interpreted from wireline log data which includes approximately 115.2 feet of gross hydrocarbons in the two Miocene targets, U7.0 and U8.0.

Erin Energy is now planning an appraisal of the discovery for the second-half of 2018, subject to the availability of capital and drilling services.

In Gambia, ERN completed a farm-in agreement in early-2017 with FAR Ltd., an ASX listed company, which has seen successful offshore activity in Senegal with its SNE field discovery and subsequent appraisal program. ERN recently announced that a subsidiary of Petroliam Nasional Berhad (PETRONAS) has also farmed into the Gambia blocks and that the joint venture plans to drill the Samo-1 prospect, which as reported FAR is estimated to contain unrisked mean prospective resources of 825 million barrels of oil.

In Ghana, Erin Energy announced that the Final Judgement was issued by the International Tribunal of the Law of the Sea on Maritime Boundary Arbitration between Ghana and Côte d’Ivoire. The maritime boundary delimited by the Special Chamber’s decision ruled in favor of Ghana and had no material impact on ERN’s Expanded Shallow Water Tano block.

Erin Energy has re-commenced work with the Government of Ghana and its joint venture partners to progress operational activities and is planning a 3D marine seismic survey acquisition later this year. ERN plans to tender the 3D seismic survey once it receives government approval.

Erin Energy’s year-end 2017 SEC proved oil reserves were 7.1 million barrels (MMbbls).


Earlier today Energy XXI Gulf Coast (ticker: EXXI) reported financial and operational results for the fourth quarter and full year 2017.

In addition, the company announced that it will change its Nasdaq ticker symbol on March 21, 2018, from EXXI to EGC.

Highlights from Q4 2017

  • Produced an average of approximately 27,600 barrels of oil equivalent (“BOE”) per day (77% oil) during Q4
  • Benefited from strong oil price realizations during the fourth quarter of $59.27 per barrel, approximately 7% higher than the WTI average price of $55.40 per barrel for Q4.
  • Reported a net loss of $215.1 million for Q4 2017
  • Capital expenditures for 2018 are expected to be in the range of $145 to $175 million.
  • In 2018, EGC plans to drill six new wells in West Delta and South Timbalier, including three development wells, one injection well, and two exploitation locations.
  • The first development well of the 2018 drilling program, the West Delta 73 C-27 McCloud, plans to be spud in March.
  • Year-end 2017 proved reserves totaled 88.2 MMBOE.

Financial update

EGC reported total revenues for the Q4 2017 of $93.8 million. In the fourth quarter, EGC produced and sold approximately 27,600 net BOE per day, which consists of 21,300 barrels of oil per day at an average realized price of $59.27 per barrel, 600 barrels of NGLs per day at an average realized price of $33.32 per barrel, and 34.5 MMCF per day at an average realized price of $2.97 per MCF.

The company reported a Q4 loss of $215.1 million which includes a non-cash ceiling test impairment charge of $145.1 million and a loss on financial derivatives of $33.3 million.

Adjusted EBITDA for Q4 and 2017 full year totaled $10.8 million and $110.5 million, respectively.

On December 31, 2017, EGC had approximately $74 million in borrowings and $202.6 million in letters of credit issued under its credit agreement. Liquidity totaled approximately $164.2 million, which consists of cash and cash equivalents totaling $151.7 million and $12.5 million in borrowing capacity available under certain conditions.


EGC currently has fixed price swap contracts benchmarked to NYMEX-WTI to hedge a total of 8,000 BOPD of production for full year 2018 with an average fixed price swap of $50.68. EGC has fixed price swap contracts benchmarked to LLS-Argus for 2,000 BOPD with an average fixed price of $55.45 for the period of January – June 2018, and 2,500 BOPD fixed price swap contracts benchmarked to ICE-Brent for January to June 2018 with an average fixed price of $56.59. The company does not have any hedges in place on natural gas production.

Proved reserves

Total SEC proved reserves as of December 31, 2017 totaled 88.2 MMBOE, of which 84% were oil, 2% were NGLs and 14% were natural gas. All of the EGC’s proved reserves are on the Gulf of Mexico Shelf or U.S. Gulf Coast, and 75% are classified as proved developed reserves.

On March 31, 2017, EGC’s proved reserves totaled 109.4 MMBOE. The primary non-commodity price factors contributing to the decline in reserves from March 31 to December 31, 2017 include actual production during the period, increased costs due to the modification of fixed versus variable LOE, reserve write-downs, and revisions of previous estimates.

Operational update and 2018 CAPEX

CAPEX for 2018 are expected to be in the range of $145 to $175 million, of which EGC will approximately spend $65 to $75 million on drilling new wells and recompletes, $10 to $15 million in planned facilities improvements, and $50 to $60 million in anticipated plugging and abandonment expenditures.

The West Delta 73 C-27 McCloud, a development well location which will be drilled to an expected total vertical depth of 8,400 feet, is expected to be spud in March, 2018. EGC has 100% working interest in this well and initial production is anticipated during the second quarter of 2018. For 2018, EGC plans to drill a total of six wells, which includes three development wells, an injection well, and two exploitation wells planned for the second half of 2018 that could add proved reserves if successful.

With the sale of its West Edmund Hunton Lime Unit (WEHLU) closed in February 2018, Gastar Exploration (ticker: GST) is now positioned to become a pure-play Oklahoma STACK Play operator. In the STACK play, Gastar is targeting two producing formations: Osasge and Meramec.

Operational update

According to Stephen Roberts, Senior Vice President and Chief Operating Officer, “As compared to the first half of 2017, we have seen a reduction in the number of days to drill a well from 19.4 to 12.4 days and reduced completion days from seven to four. Based on efficiency improvements, our current cost per well is expected to be approximately $4.5 million for Osage wells and $4.7 million for Meramec wells.”

During 2017, Gastar spud a total of 11 gross (3.1 net) operated Meramec and 17 gross (11.5 net) operated Osage wells. In addition, Gastar completed 15 gross (3.8 net) operated Meramec and 16 gross (10.6 net) operated Osage wells and participated in numerous third-party wells across its 67,000 core STACK Play acreage. This highly contiguous position is 84% operated and 66% held by production.

So far in 2018 Gastar spud three gross (2.5 net) operated Osage wells and completed two gross (1.8 net) operated Osage wells.

Q&A from conference call

Q: Clearly, a much better shape post the WEHLU sale. But with that in mind, first, how are you guys thinking about the preferred dividend at this point? And then secondly, I noticed kind of a brief sentence in the press release that mentioned the potential for future property sales if necessary. I was just curious what those would be comprised of.

Senior Vice President and CFO, Michael A. Gerlich: Regarding the preferred, as we stated before, it’s always been and continues to be our intention to catch up and reinstate the preferred dividends. We say that we needed to complete the WEHLU property sale, and that’s now been completed. Typically, preferred dividends are declared by the 10th of a month with a record date about 10 days later, and then the dividends are paid at the month-end of the announcement. Again, it remains our intention to catch up the dividend payments in arrears, reinstate the preferred dividends. And those assumptions were factored into our 2018 budget and liquidity projections. So, it’s really not going to have the reinstatement will not have an impact on our plans for 2018.

Regarding the overall question on liquidity, obviously, the closing of WEHLU has given us ample liquidity, as I said, to execute our 2018 budget and should carry us into 2019. We continue to evaluate our capital needs and compare them to our capital resources and our ability to raise funds in the capital markets or through the sale of – really what the focus will be is non-core lease acreage. And our definition of non-core is more small blocks of acreage we own in sections we know we will not operate. We’ll either look at monetizing those or maybe trading them to enhance our working interest position in our operated sections.

So, fortunately, we have the ability to adjust our capital expenditures in response to changes in commodity prices, drilling results, liquidity and cash flows, as we operate the majority of our capital expenditures. So, we’re going to continue to review our options over the next few months, including strategic alternatives. But again, since we’ve got a pretty good handle on our outflow since we operate it, we’re not concerned about an immediate liquidity crunch.

Q: I was wondering, Stephen, you talked a lot about the operations there, and obviously, you get some better drilling and completion times in. As you talk about the Gen 3 completions, I think you guys are using some diverters and things. But is there anything else that’s kind of different in those that you’re seeing the good response from?

Senior Vice President and COO, Stephen P. Roberts: We mentioned in our previous call and even prior to that that we tried to reduce cost early last year by stripping out a lot of the additives and going to really a completion provider that we just weren’t happy with. And we’ve made all those changes, and we continue to test. And I mentioned that we’re continuing to test the various additive surfactants, clay stabilizers, diverters, et cetera, and certainly feel like we’re getting an uptick in our production performance associated with those.

Again, as mentioned too, I think it’s very important to note as well that we do see what we think is improved production performance here with the 35-stage wells. So, there is a likelihood that we will begin to transition most of our completions to 30 or 35 stages. Again, we’ve got more history on those than we do on a lot of the 25. So, we’re still watching those and still very pleased with initial results there. But again, we think that 35 stages are performing really above type curve at this point. So, that’s the direction we’re moving.

Q: And then also you talked a bit about, at some point, being able to shift from holding acreage to the pad drilling, and I think if I saw the number, you’re about two-thirds held by production now. As you see this year play out, where do you think that that number goes and when do you maybe start to look at the pad drilling for at least some of your operations in the future?

Stephen P. Roberts: I’ll take that and then may defer to Mike as well. But right now, our absolute focus is on continuing to push our costs down while simultaneously improving production performance, and that all in conjunction with HBP-ing the rest of our acreage. So, we will likely be fully HBP-ed sometime next year as we continue to add operated sections that may be pushed out a tiny bit based on a one rig schedule, but certainly watching other operators and noting the improvements they’re seeing from pad drilling and recognize that there are certainly significant cost reductions there that we can recognize from pad drilling. But again, our focus this year really is the HBP process and continuing to refine our execution and design.

Michael A. Gerlich: I’ll just add a couple of things following up on HBP-ing. He’s correct. We’ll have the majority of our operated HBP probably sometimes early 2019, at which time we will start looking at moving to pad drilling. We are aware of some of the operators in the STACK recently reporting some negative down spacing test results. We’re also aware that another operator that has acreage adjacent to ours has reported positive down spacing testing. Some of those tests were actually in close proximity to the operators that reported some of the negative results. At this point, we’re going to, as Stephen said, continue to focus on holding HBP-ing our acreage, and then once we start doing our own, we’ll talk about down spacing. But our spacing assumptions are basically on par to those with the good results. We’re looking at 6 in the Meramec and 7 wine rack in the Osage, and we don’t think we’ve been overly aggressive on that aspect. Obviously, it’ll be sometimes probably till 2019 until we can start proving up those assumptions.

Q: Operationally, what does the split kind of look like between Meramec and Osage as we go throughout 2018?

Stephen P. Roberts: Osage is definitely going to be lion’s share, and I think we said, 15 Osage wells and I believe 5 Meramec wells. So, definitely the lion’s share in Osage, and again we feel like the Osage exists and has significant thickness across our entire position, where we’re still testing that theory with the Meramec, certainly thick toward the southern end. And we continue to stretch that northern border. Some of our more recent, very successful Meramec tests have been 1 mile step out to the north of where we’ve previously been. So, we’re really excited about results of both, but feel like the Meramec to some degree is proven up, and we’re continuing to delineate and prove up Osage, so hence, the primary reason for the lion’s share being Osage going forward.

Q: You talked about running into the chert, and I think that’s in the Osage. Is that kind of running into  stringers or just maybe talk a little bit more about that and how you’re dealing with that.

Stephen P. Roberts: Yeah. Oh, absolutely. It can be stringers and it can come and go. But we also see it in some instances where it can be a little more blocky and contiguous – but in either case, we think we have addressed it. We did run into it three or four times towards the end of last year and the beginning of this year, and it presented us with a few problems. If anybody out there is aware operationally, chert is virtually impossible to drill if you stay in that interval. And the BHAs that you have to use to drill in chert can be very conservative in terms of ROP.

So, we have developed a strategy basically of dropping our curve. Well, one – I guess it’s really kind of a three-part strategy. One, we’ve drilled enough wells now and delineated enough that we know, to a large degree, geographically and through vertical depth-wise where we’re going to encounter the chert. So, we’re anticipating it as we go. As we drill down through and looking for it, we’ll typically try to drill through that interval with our curve before we set 7-inch casing. And typically, you’ve got a BHA that’s somewhat worn at that point anyway. So, if you do a little damage to the bit, really no concern. Identify what you’ve got and get through it, set your 7-inch and now you’ve kind of set a target of where that chert is, and then quickly move back to a very aggressive BHA, i.e., a PDC bit and then continue with very smooth, very efficient ROPs.

So, that we have implemented actually on the last several wells and the last two have actually – we just TD-ed another one just actually yesterday and we’re at very good times. We’re in that 10, 11, 12-day TD time, so really excited about that and getting well times down. That was really our last lingering issue on drilling and virtually every other issue has been resolved at this point.

Read Gastar Exploration Inc. 10-K here

March 2, 2018

Penn Virginia Corporation (ticker: PVAC) announced its financial and operational results for Q4 2017 and full year 2017.

Operational Highlights

  • The two-well Geo Hunter pad had a 30-day initial production (“IP”) rate of 3,767 BOEPD and a previously announced 24-hour IP rate of 5,465 BOEPD. In addition, PVAC recorded a 24-hour IP rate from its Southern Hunter Amber two-well pad of 5,092 BOEPD. Both pads utilized the company’s slickwater completion design;
  • PVAC produced 3.8 MMBOE or 10,353 BOEPD (73 percent crude oil), for full year 2017, including 12,340 BOEPD (74 percent crude oil) in the fourth quarter of 2017. This represents a 32% increase over the fourth quarter of 2016. PVAC achieved a 2017 exit rate of approximately 14,650 BOEPD. PVAC has a targeted year-over-year production growth of approximately 125% for 2018 under its current development program;
  • PVAC increased proved reserves by approximately 47 percent to 72.6 BOE representing 710 percent of 2017 production at a drill-bit finding and development cost of approximately $4.40 per barrel of oil equivalent;
  • The company increased drilling locations at year-end to 500 net (589 gross), of which approximately 80 net locations (100 gross) are higher rate of return extended reach laterals (12 in Area 1 and 68 in Area 2)
  • PVAC closed the previously announced acquisition of Eagle Ford assets located primarily in Gonzales and Lavaca Counties, Texas, from Hunt Oil Company on March 1, 2018.

Penn Virginia drilled and turned to sales nine gross (5.3 net) wells during Q4 2017, all of which were in the Eagle Ford Basin. The Geo Hunter pad had a 24-hour IP rate of 5,465 BOEPD, representing 394 BOEPD per 1000 feet lateral. The pad produced 3,767 BOEPD for an IP-30 rate. After the Devon acquisition which was closed in Q3 2017, the company holds 93.2 percent working interest.

In early February 2018, PVAC turned to sales the Southern Hunter Amber pad in Area. The average lateral reach for wells completed on this pad was 8,100 feet. The pad recorded a 24-hour IP rate of 5,092 BOEPD, and the company holds 98.1 percent working interest.

At the end of 2017, Penn Virginia held approximately 73,400 net acres in the Eagle Ford. Pro forma for the Hunt acquisition, the company has approximately 83,100 net Eagle Ford acres with 39,100 in Area 1 and 44,000 in Area 2.

Including the Hunt acquisition, by the end of 2017 PVAC had an estimated 589 gross (500 net) drilling locations and 100 gross (80 net) are anticipated to be extended reach laterals. Approximately 93% of Penn Virginia’s core acreage is held by production.

Proved Reserves

In 2017, PVAC’s total proved reserves increased approximately 47 percent to 72.6 MMBOE compared to 49.5 MMBOE at the end of 2016. The composition of the proved reserves included 77 percent oil, 12 percent NGLs, and 11 percent natural gas.  Out of the proved reserves, 44 percent are classified as proved developed.

PVAC’s standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves was $590.5 million as of December 31, 2017, increasing from $317.6 million as of year-end 2016. The increase was primarily a result of increased proved reserves and the average NYMEX oil and natural gas price.

Financial highlights

  • PVAC reported a net loss of $10.8 million, or $0.72 per diluted share, in the fourth quarter of 2017. Adjusted net income was $15.8 million, or $1.06 per diluted share, in the fourth quarter of 2017. Net income was $32.7 million, or $2.17 per diluted share, for the full year 2017. Adjusted net income was $43.4 million, or $2.88 per diluted share, for the full year 2017;
  • Generated adjusted EBITDAX of $37.4 million in the fourth quarter of 2017, representing a 78 percent increase compared to Q4 2016, or approximately $32.97 per BOE. For the full year 2017, PVAC generated adjusted EBITDAX of $102.2 million, or approximately $27.05 per BOE;
  • Increased the borrowing base under its credit facility by more than 40 percent to $340 million, effective March 1, 2018. Current availability under the credit facility is $164.2 million.

Q4 2017

Total direct operating expenses for the company, which include LOE, gathering, processing and transportation, severance and ad valorem taxes, and cash general and administrative expenses, were $15.9 million for Q4 2017. This represents a $2.2 million increase compared to Q4 2016.

Net loss for Q4 2017 was $10.8 million, compared to a net loss of $1.9 million in Q4 2016. Adjusted net income was $15.8 million in Q4 2017, compared to $10.7 million in Q4 2016.

Adjusted EBITDAX was $37.4 million in Q4 2017, representing a 78% increase from the fourth quarter of 2016.

Full Year 2017

Total direct operating expenses for PVAC were $55.8 million, or $14.76 per BOE in 2017. Net income for 2017 was $32.7 million, with and adjusted net income of $43.4 million.

Adjusted EBITDAX was $102.2 million for 2017.

Hunt acquisition

Yesterday on March 1, 2018 PVAC closed the previously announced acquisition of assets in the Eagle Ford Shale, primarily in Gonzales and Lavaca Counties, from Hunt for $86 million in cash, subject to adjustments. The acquisitions provided proved reserves of approximately 12 MMBOE (86 percent oil) and provides a total resource potential of approximately 29 MMBOE.

Balance Sheet, Liquidity, and 2018 CAPEX

During Q4 2017, PVAC incurred $55.7 million of capital expenditures (excluding acquisitions), and 95 percent was associated with drilling and completion capital. For the full year 2017, PVAC incurred $133 million of capital expenditures, and 94 percent was associated with drilling and completion capital.

Concurrent with the closing of the Hunt acquisition, PVAC’s borrowing base increased to $340 million from $237.5 million. As of December 31, 2017, PVAC had $77 million outstanding on its credit facility and liquidity was $170.7 million. As of March 1, 2018, the PVAC had outstanding borrowings of $175 million, resulting in $164.2 million available under the credit facility.

Capital Expenditures for 2018 are expected to total between $320 and $360 million, with 95 percent of the capital being direction to drilling and completion operations in the Eagle Ford. PVAC plans to drill a total of 55 to 60 gross (45 to 50 net) wells. 33 to 35 of those gross wells are planned to be drilled in Area 1, and 22 to 25 of those gross wells are planned to be drilled in Area 2. In 2018, PVAC plans to drill 22 extended reach lateral wells.

Callon Petroleum Company (ticker: CPE) reported results of operations for the three months and full-year ended December 31, 2017.

Financial and operational highlights

  • Full-year 2017 production of 22.9 MBOE/d (78% oil), an increase of 50% over 2016 volumes
  • Fourth quarter 2017 production of 26.5 MBOE/d (79% oil), a sequential quarterly increase of 18%
  • Year-end proved reserves of 137.0 MMBOE (78% oil), a year-over-year increase of 50%
  • Organic reserve replacement(i) of 566% of 2017 production at a “Drill-Bit” finding and development cost concept(i) of $8.21 per BOE on a two-stream basis
  • Reduced lease operating expense to $4.84 per BOE in the fourth quarter of 2017, a sequential quarterly decrease of 5%, contributing to a total reduction of 27% since the first quarter of 2017
  • Generated a fourth quarter operating margin of $40.51 per BOE
  • Currently operating five horizontal rigs and two completion crews

According to the company’s press release, by December 31, 2017, Callon Petroleum was producing from 232 (171.8 net) horizontal wells from eight established flow units in the Permian Basin. Compared to the same period in 2016, Callon increased its net daily production by approximate 44% to 26.5 MBOEPD (approximately 79 percent oil). The total full year average production for 2017 was 22,940 BOEPD (approximately 78 percent oil), reflecting a 50 percent growth compared to 2016 volumes.

Midland Basin

In Q4 2017 over 50 percent of well put on production were form the WildHorse area, averaging completed lateral lengths of approximately 7,300 feet. The Wildhorse area is a key component of production growth for Callon, and is projected to comprise of 30 percent of total gross drilling activity in 2018. The Wolfcamp A bench will be a primary focus for development in the Wildhorse area in 2018, and average completed lateral lengths are projected to increase to over 8,000 feet.

In addition to the Wildhorse Area, six wells were put on production in the Monarch Area. The Lower Spraberry will be a key focus, due to the consistency of high returns. The three-well Kendra pad, with average completed lateral lengths of approximately 10,350, has produced over 236,000 BOE (87% oil) over the first 90 days online. Callon also initiated production from the first multi-well pad that utilized recycled flowback water, and plans to increase recycling activity in Monarch for upcoming wells.

Mega-Pad concept

In 2018 Callon plans to incorporate two separate “mega-pad” concepts incorporating simultaneous development of two contiguous three-well pads. Each bad will be drilled concurrently and all six wells will be placed on production at the same time. The pads are expected to be put on production during the second half of 2018.

In the Reagan County at the Ranger area, Callon completed its first Wolfcamp C well, along with two Lower Wolfcamp B wells. The wells began flowback in January 2018. The Wolfcamp C well is producing over 1000 BOEPD (85-90 percent oil) on natural flow, and is still in the process of establishing a peak rate. In 2018 Callon plans to drill four gross additional wells in Wolfcamp C with an average working interest of approximately 55 percent.

Delaware Basin

Callon recently completed its first two-well pad and added a second rig to its Spur development program in February. To accommodate the increased activity, Callon plans to enhance existing saltwater disposal capacity to overall 100,00 bpd with a connection to a pipeline system operated by Goodnight Midstream. Callon is in the final stages of establishing a recycling program in the area, and is projected to use up to 50 percent recycled volumes for completions by the end of 2018. In Q4 2017, the Saratoga 7La well came online and has produced an average daily rate of 1,015 BOEPD (83 percent oil) for its first 56 days of production.



CAPEX, financial results, and proved reserves

Operational capital expenditures for the Q4 2017 was $115.8 million, compared to $113.4 million for Q3 2017. Callon also divested certain infrastructure during Q4 for proceeds of just over $20 million.

Callon reported total revenue of $118.2 million for Q4 2017 and total revenue including cash-settled derivatives of $113.7 million. Lease operating expenses for Q4 2017 was $5.41 per BOE, compared to $5.60 per BOE for Q3 2017. Production taxes were $2.55 per BOE, and DD&A was 14.98 per BOE for Q4 2017.

AS of December 31, 2017, Callon estimated total proved reserves at 137 MMBOE, which represents a 50 percent increase over the previous year-end. Callon added a total of 47.4 MMBOE in 2017 from horizontal development properties, replacing 566% of 2017 production as calculated by the sum of reserve extensions and discoveries, divided by annual production.

Conference Call Q&A

Q: So, I had a question on well interference, we’ve heard a number of your peers talk about parent-child relationships and two-type spacing. How do you see these risks for Callon – or the industry and what steps have you kind of taken to mitigate these?

Senior Vice President and COO Gary A Newberry: That’s something that we’re all learning about together as we go forward. We’ve been stepping into this in a way that, I think, has been very educational and learning. Frankly, part of the reason we’ve actually gone to pad development from the very beginning was to minimize that impact early on throughout the entire lifecycle of our drilling program. Since early time, we’ve been doing mostly pad wells.

But as we get into infill drilling, just similar to what we did in CASM, and really some parts of Ranger, we have the majority of our experience with parent-child relationship, de-watering or deferred – or watering out and deferred production and ultimately, the ability to effectively fracture stimulate the offset wells based on depletion.

So, there’s a lot of things that are impacting this entire relationship. But in total, as we’ve down-spaced in both the Wolfcamp B in Reagan County and as we’ve down-spaced the Lower Spraberry in Midland County primarily around all the things that we’ve actually published data on over the last several quarters, we think we’ve mitigated that impact quite well.

Now, the next step for us is to move to this larger pad development, which is what we’re moving through now and Monarch this year to further minimize and mitigate the impact of deferred production from de-watering existing wells as well as more effectively and efficiently propagating effective fracture stimulations into this shale development in a larger way.

So, we think it’s going well. I think it’s something as we continue to mature in each area that it’ll be different. But I think the data that we’ve shown you is that it seems to be working well and there will clearly be an impact. We’ve mentioned it before, there’s clearly an impact to that next well over, but it can be mitigated if planned properly.

Q: You guys have been early on in infrastructure build out. How much kind of headroom do you guys have over your production guidance in 2018, first, your current infrastructure or what you’ll have midyear?

Senior Vice President and COO Gary A Newberry: We’re well ahead of what our needs are, but our production growth both in water and oil is that we’re expecting that to be substantial. So, at the end of the day, we’ll never be finished. What we’ve done ourselves, frankly, in getting to pipeline infrastructure for water management, getting to our own deep disposal wells for water management, high-capacity deep disposal wells to avoid shallow hazards. We are now partnering with third-party companies to help actually manage some of that peak loading that we expect on some of these larger pad developments.

We’ve already announced actually in the Delaware Basin a long-term relationship with Goodnight Midstream and we’re anxious to talk about another relationship on water sourcing and disposal with another company that we’re working on right now, both in the Delaware as well as the Midland Basin. We’re just not quite ready to do that yet. We’re still working on a few other items with this other company, but they’re being very proactive in doing all the right things in our mind.

And the focus on recycle that we’ve had for a number of years is going to be very impactful in managing all of our needs throughout the area. So, I would say that we’re ahead of where we need to be, but we’re not quite done. That’s why we’re spending primarily money in the Delaware Basin yet to further enhance our ability to move water around to our own disposal wells and then ultimately to delivering into the Goodnight system.

Q: I was hoping we can maybe just start a little bit on the Saratoga well and the Delaware Basin. I was curious if this was one of the operating completions in which you intended on reining in proppant intensity and just overall completion intensity in an effort to get the well cost down. So, maybe if you can just talk a little bit more about the completion design and the cost?

Senior Vice President and COO Gary A Newberry: We pulled back sand loading a little bit on that well, just like we had intended to actually get another learning step on how we effectively stimulate a single well, as well as ultimately moving to multiple well pads in that area. This well is performing quite well based on what we see today. We’re happy with the performance. But there’s still more to learn as to how we go forward in the Delaware. But yeah, we pulled back on sand loading just like we said we would.

Q: I guess the Wolfcamp C, a nice result there. Curious about any updated thoughts on the Wolfcamp D? I know at one point, you did plan on testing the zone at Ranger in 2015. Just given some recent competitor results, do you think about testing that at any point this year?

Senior Vice President and COO Gary A Newberry: There’s a lot in that question, but, again, I want to emphasize we’re very focused on efficient development throughout the year, but we are encouraged with the Wolfcamp C in the Reagan County. It’s very early time. You guys know I don’t like talking about single well results. I’d never have, never will. It is a single well. We’re encouraged with it. It’s a well that is encouraging enough that we’re going to drill more wells. But I’ll tell you that I have as many questions about the well as I have answers. So, it’s still just a single well result with encouraging information early time.

So, with that, we’re going to do more. We’re encouraged that we’re actually able to participate near-term with another well as an OBO partner, carries on with one of the area wells down there soon. So, we’re anxiously learning about that. And we’re learning as much as we can from all the public results, of course, from the Parsley data that we can get because their Taylor well is an interesting well. This well doesn’t feel like a Taylor well to me, but it’s encouraging. So, I’ll just leave that the way it is with the Wolfcamp C.

Your last question was with the Wolfcamp D. And I think, again, I’m assuming still Reagan County because that’s where we had planned to drill one prior to pivoting at the end of 2014 to the Monarch area. There’s some very good results, very interesting results being delivered by offset operators there today and we’re very encouraged with that opportunity. We’re not prepared to go drill our own this year at all.

President and CEO Joseph C. Gatto: So, I think, overall, we do have some delineation work going on in both Midland and Delaware. But as it relates to our overall program, it is in the single-digits, on a percentage basis, in terms of capital exposed. So, some of that’s having some lower working interest, which helps us get into some more wells with lower capital exposed, but we have those opportunities, like you said, in the Wolfcamp D. They’re on the radar screen. It’s just probably not on this radar screen for 2018, but it’s good to see those results continuing to come in the de-offsetting as in Reagan.

Q: The 2018 plan includes progressing larger pad development concepts that you discussed, the mega pad in Monarch, for example. Other than this development, what’s the average pad size for 2018 versus 2017? And what do you think the optimal pad size is, given your footprint, and whether or not the pad size plays into any execution objectives you have for this year?

Senior Vice President and COO Gary A Newberry: We’re really focused on fully understanding the asset base in its entirety in the Delaware Basin. And even though we’ve just finished a two-well pad, we’re going to focus on single well pads primarily in the Delaware for this year. But in WildHorse, we’ll go to two and three-well pads. And that’s all aligned in some lease obligations as well as trying to mitigate this parent-child relationship that we talked about earlier, as well as deferred production.

So, it all depends generally on what our obligation wells are, how we want to mitigate future development impacts, as well as cycle time and efficient development for what we’re trying to do throughout 2018. Monarch is where we’re going to do the six-well pad. We invested in infrastructure several years ago. We’re well setup with our own disposal as well as third-party disposal, as well as a recycle there to do that very efficiently. And we think that’s the best place to jump right into that.

We’re learning actually about a lot of things in pad size and development going forward. Given the pace that we think is a responsible pace to run and the capital levels to invest, we’re partners in some multi-level, multi-well pad development in Howard County with some of our offset operators and we’re learning a lot from that. So, more to come on it. It’s something as we think about it in a lot of detail in our planning process in order to effectively and efficiently bring value forward. It’s a little different in each area. But over time, we believe we’re headed to bigger and bigger pads.

Q: My question is on Delaware Basin and Ward County. You guys got some of the best acreage that I can think of. And just wondering if there’s any plan to look at the Bone Spring, because there has been activities from your competitors. And then, ultimately, when you look at the Delaware Basin, understanding how well you guys have worked your margins in Midland Basin, do you think you can approach similar cash returns in light of the probably higher water handling costs?

Senior Vice President and COO Gary A Newberry: We’ve got some great acreage in the Delaware. We’re happy to have it. We’re happy to go learn as much as we can about it this year through the planned and dispersed development program that we have. We’re very focused on reducing cycle time, managing costs out of system, as well as, as we’ve already discussed, building the appropriate infrastructure necessary to be very efficient with managing the higher water-loading that is associated with the Delaware. And I think we’re ahead of the curve there. I think that the innovative and creative solution we’ve gotten with Goodnight Midstream, I’ve already referenced it, and I can’t speak too much more about it other than the water sourcing arrangement that we have with a third-party company.

The water recycling system that we’re doing on our own self and do it with ourselves as well as in our own infrastructure is going to be very critical in managing costs. And so, we see plenty of opportunity to further improve the margins in the Delaware, similar to what we’ve done in the Midland Basin.

Q: Maybe I’ll just kind of get your latest thoughts on M&A. Are you looking to continue expanding your footprint? And if so, which area do you see the greatest opportunity to continue adding acreage?

President and CEO Joseph C. Gatto: I think, simply put, yes, we are continuing to look at expanding the footprint. The focus has largely been on continuing to bolt-on around our footprint in the four core operating areas and we’ve made progress in all four of them over the last several quarters. So, that’ll continue to be the priority.

There are some potentially larger transactions we look at, but the way we think about that is we want them to be in and around our existing footprint. We’re not looking to add a fifth core operating area at this point and grow our opportunities out there. There’s a lot of transactions that didn’t clear the market last year that are probably swinging back around, and we’ll watch. But the good thing is we have a very deep inventory right now to work on these smaller types of opportunities that are very value added. They fit into the drilling program near-term and bring forward the PV proposition.

Q: Throughout earnings to-date, gas evacuation has become a topical discussion point for Permian producers in light of growth plans within the region. While you guys are quite a bit older than your peers, could you comment on your thoughts on gas macro in the basin and how you position the firm to mitigate risk?

Senior Vice President and COO Gary A Newberry: I think you started off right, and would remind everybody that about 77% of our equivalent net production is oil. Of the remaining 23%, roughly one half is natural gas that is sold into the Waha market. We’re not seeing any flow concern issues to date. We have gas gathering contracts in place and our gatherers are incentivized to flow 100%. So, we’re not seeing those issues to date.

We are actively considering some basis trades to mitigate differential risk. I know that this is an issue throughout the basin for some, but I just want to highlight on a revenue basis, a $0.25 per MCF movement in Waha differentials will impact our total revenues by less than 0.5% or 1%. It’s really – for us, we have the flow capacity and it’s just not meaningful when you add it all up.

President and CEO Joseph C. Gatto: So, for us, there’s a financial element there that Jim had talked about. But when we started talking about this topic several quarters ago, it was really a focus on how do we move the gas volumes because we want the oil, right. I mean, we’re close to 80% oil in Delaware. It’s not like we’re differentiated between Midland and Delaware. So, the focus of the team was let’s make sure we can move the gas.

And I think going through that analysis, looking at the pipes and the takeaway, feel pretty comfortable that there is physical takeaway there. It might mean that you’re getting into gas on gas competitions in markets that are going hurt the Waha basis. But in terms of evacuating and moving the methane volumes, we feel pretty comfortable. There’s a pass out of the basin that just becomes a price aspect and we need to continue to work on how we mitigate some of those price impacts. Although, as Jim pointed out, even with some of that adverse movement, it’s pretty negligible in terms of the grand scheme of our revenue picture.

‘A couple of engineers are significantly less expensive than a poorly completed well – EP’s Russell Parker’

On February 28, 2018 Ep Energy Corporation (ticker: EPE) announced fourth quarter and year-end 2017 financial and operational results.

Key highlights

  • New leadership team in place
  • 3 thousand barrels of oil equivalent per day (MBOEPD), including 46.1 thousand barrels of oil production per day (MBOPD)
  • $587 million of oil and gas expenditures, including acquisitions of $29 million
  • 149 completed wells
  • $194 million net loss / $691 million Adjusted EBITDAX
  • Entered into Eagle Ford acquisition and Altamont acreage divestiture – closed 1Q’18
  • Improved financial flexibility with extended debt maturity profile

Financial results for Q4 2017 and full year 2017

In Q4 2017, EP Energy reported a $0.29 diluted net loss per share and $0.07 adjusted loss per share, according the company’s press release. The reported net loss for Q4 2017 was $72 million, compared to a $140 million net loss for the same period in 2016. The decrease in net loss was a result of higher realized pricing on oil and NGL volumes and lower reported general and administrative costs.  Adjusted EBITDAX for Q4 2017 was $181 million, down from $255 million in the fourth quarter of 2016, due to $118 million less of hedge settlements and lower total equivalent and oil volumes in 2017 versus 2016.

Operating expenses for Q4 2017 were $217 million, which is $30 million less than the same quarter in 2016, due to lower reported general and administrative costs. Capital expenditures for Q4 2017 were $145 million, which represents a $29 million increase from Q4 2016, due to increased drilling activity in the Eagle Ford Basin in 2017. During Q4 2017 EP Energy completed 30 gross wells, including 14 in the Eagle Ford Basin, seven in the Permian Basin as part of the company’s joint venture, and nine in the Altamont drilling joint venture.

For 2017’s full year, EP energy reported $(0.79) diluted net loss per share and $(0.39) adjusted loss per share. Reported net loss for 2017 was $194 million, compared to a $27 million net loss for 2016, which included approximately $450 million of gains on extinguishment of debt and asset sales in 2016.

Adjusted EBITDAX for the year 2017 was $691 million, down from $1,039 million in 2016 due primarily to $546 million in lower hedge settlements offset by higher realized pricing on oil and NGL volumes in 2017.

Total operating expenses for the year ended December 31, 2017 were $927 million, which represents a $62 million increase from 2016. The difference was driven by a $78 million gain on the sale of the Haynesville assets in 2016.

Capital expenditures in 2017 were $587 million, representing a $99 million increase from the same period 2016.  In 2017, the company spent $227 million in the Eagle Ford, $267 million in the Permian (including $29 million of acquisitions) and $93 million in the Altamont. Throughout 2017, the EP Energy completed 149 gross wells, which represents approximately 50 more wells than EP Energy completed in 2016.

As of December 31, 2017, EP Energy’s balance sheet included $4.1 billion of total debt and approximately $27 million of cash and cash equivalents. In January 2018, EP Energy successfully exchanged and extended the maturity on approximately $1.1 billion of senior unsecured notes maturing in 2020, 2022 and 2023 for new senior secured notes maturing in 2024. As of December 31, 2017, the company had approximately $800 million of total liquidity.

Operational highlights

For the year ended December 31, 2017, average daily production was 82.3 MBOEPD, including 46.1 MBOPD of oil.  Fourth quarter 2017 average daily production was 80.6 MBOEPD, including 43.6 MBOPD of oil.  The decrease in the third and fourth quarter production was due to the timing of Eagle Ford activity that was focused early in 2017.

Eagle Ford Basin

In 2017, EP energy completed 43 wells in the Eagle Ford and production was 35.7 MBOEPD, representing an 18 percent decrease from 2016. In Q4 2017, the company completed 14 wells and produced 30.6 MBOEPD, representing a 19 percent decrease from Q4 2016. EP energy expects to increase year over year annual production for the first time since 2015.

The Eagle Ford horizontal shale inventory was expanded by approximately 200 future drilling locations with the acquisition of producing properties and undeveloped acreage from Carrizo Oil & Gas, Inc., which closed in January 2018.

In the Eagle Ford, EP has increased current production by 20 percent compared to the Q4 2017 average. The increase was partly driven by performance of new wells, and partly driven due to the acquisition. The increased production includes four Ritchie Farms in-fill pad child wells that have been online for 25 days, along with four new Volatile Oil wells completed in December and January that had 60-day oil rates 30 percent higher than predicted.



Permian Basin

In 2017, Ep Energy completed 71 wells in the Permian Basin and produced 28.7 MBOEPD, representing a 34 percent increase form 2016. In addition, EP energy completed several bolt-on acquisitions in Upton County which added current production and future drilling locations. The cost for the acquisitions was approximately $29 million and included approximately 3,600 net acres in the Upton county with gross oil production of 300 BOPD. This transaction added roughly 60 future drilling locations to the company’s portfolio, and enabled EP Energy to extend approximately 20 short lateral locations to long lateral locations.

Altamont Field

In 2017, EP Energy completed 25 wells and performed 59 recompletions in its Altamont Program. Full year production was 17.9 MBOEPD, representing an eight percent increased compared to 2016.

Hedging update

In 2017, EP Energy realized $93 million from settlements on financial derivatives. For 2018, EP Energy has effectively hedged approximately 89 percent of its expected oil production at an average price of $58.47 per barrel, and hedged approximately 56 percent of its expected natural gas production at an average price of $3.04 per MMBtu.

Proved Reserves

EP Energy’s proved oil and natural gas reserves were 392.1 MBOE as of December 31, 2017, representing a nine percent decrease compared to proved reserves at December 31, 2016 of 432.4 MMBOE. Proved developed reserves increased seven percent from 204.6 MMBOE in 2016 to 218.3 MMBOE in 2017. In 2017, proved developed reserves were 56 percent of total proved reserves and 52 percent oil.

The primary reason for the decrease in proved reserves from 2016 to 2017 was divestitures relating to the company’s two drilling joint venture and ownership changes, resulting from higher WTI prices under the variable royalty rates agreement with University Lands. Without the impact of divestitures and ownership changes, 2017 and 2016 proved reserves were essentially the same, the company said.

Conference Call Q&A

Q: Could you give a little more color on some of those parent-child wells? Obviously, there’s been some concern in the industry on the issues with the child well. But it doesn’t seem like it’s occurred with you all. When you look at it, is that related to the reservoir, maybe how the parent well was initially drilled and completed? Or is it just your approach to really putting a specific sort of a drill and complete kind of technique on that child well?

President and CEO Russell E. Parker: Historically, we have seen parent-child interference. That whole situation starts with actually the completion of the parent well. If your completion is inefficient and if your fractures happening at every cluster. If your frac lengths are unequal, then what happens is you get inefficient drainage and you potentially end up creating pathways that will connect to your in-fill wells. It does not mean you’ve actually drained the entire lease. It just means that you can communicate between wells during completion.

And so, what do you do about that? Well, first and foremost, as you’re completing new parent wells, what you really want to do is iterate upon your designs to try to get the most homogeneous frac half lengths on the new well. Now, when you’re coming into an in-fill situation such as with these eight wells, what you really need to look at is: where are the wells landed, do the benches communicate, what’s the hydrocarbon in place, what is our recovery factor have been to-date and are there any indications that we have certain communication pathways during certain parts of the offset lateral that we’re just about to complete. And also, you have to take into account spacing.

So, in certain areas, what you may want to do is actually space your wells a little bit further apart, but you put a little bit larger pound per cluster completion on those wells in order to still drain the same amount of rock. And you may want the clusters even further apart to make sure that you’re not getting negative interference. But it’s a very granular process. We have a number of really high-quality technical staff members here that dig into this, and we’re doing what’s called rate transient analysis and even simulation on the fracture design and how the fracs propagate through the reservoir on each and every pad. It takes a little bit of extra work. You have to roll up your sleeves. But I will say this, a couple of engineers are significantly less expensive than a poorly completed well. So, that’s the approach we’re taking.

Q: And I guess from our seats and the investor seat, the one big concern would be doing this seemed very costly, right? And when everybody else is going in the direction of manufacturing mode and reducing costs and trying to fight service inflation, this seems to be going into the face of that. What are the ways to mitigate some of the cost pressures on being so specific going forward?

President and CEO Russell E. Parker: Two things. One, when you’re trying to mitigate the parent-child interference, part of what you end up finding is that you actually find places in your in-fill well that you do not need to complete, which ends up saving you some costs. So, if you just blast the whole well with the exact same design that you’ve had on other wells, invariably, you’re going to get communication, right. And you ended up completing part of the lateral that you possibly didn’t have to. So, that mitigates part of the costs. The other way to mitigate the costs is to make sure that you have the right contractual relationships with your vendors to where they can make their margin, but you’re not pricing yourself in.

And this is what happens. When you get in manufacturing mode, you end up pricing yourself into one exact design, and the efficiency comes from pumping that same design over and over and over, whereas we tend to look more at, well, how do we get efficient by pumping a certain number of hours in a day and making sure that we’ve solved all of our sand logistics and our water logistics such that the efficiency comes from consistent operation at the surface. But down-hole, we have a very specific design. And the good news is you can execute that specific design with those efficient surface operations. You just want to build your contractual relationships with your vendors around that. And that way, it works as a win-win for everybody. But it’s thinking creatively about how you put all that together.

Q: We’ve spoken here most of the call on some of the operational side, and I wonder if you could talk a little bit more on the financial side, specifically how you’re thinking about balance sheet management, leverage targets and the balance of CapEx and cash flow short to medium-term.

Senior Vice President, CFO and Treasurer Kyle A. McCuen: Leverage ratio wise, I think we talked about on our call last month that we expect to improve year-over-year. Our target is to get to a half turn to a full turn better on total net debt to EBITDAX versus 2017. And then, in terms of improving the balance sheet over time, we are making headway in 2018. We’re reducing the outspend. So, that’s driven by the improvement in the capital efficiency of the assets. So, although we are spending a little bit more capital year-over-year, we’re closing that gap. And so, longer term, it’s to completely close that gap. And so, as we make headway on capital efficiency, we’re going to look at doing accretive A&D, and we think that’s a big part of kind of closing the remaining gap. And so, that’s kind of our plan medium-term to long-term.

President and CEO Russell E. Parker: In 2017 – there’s two ways you get there. One is by reducing your maintenance capital. So, let me speak to that for a minute. In 2017, we thought that number was right at about $600 million. This year, our fully-loaded D&C, so just the base level business drilling and completion, is going to be about $565 million, which is about the same as last year. However, we’re causing a rate bump with that over the year. So, if we were to scale that back down to just hold rate flat, let’s say, to quarter four, if we just wanted to hold that rate flat, we think that number is closer to $500 million now. Because remember, in our CapEx guidance for this year to get to the $625 million midpoint, that includes about $60 million of the new projects that we’re really not giving ourselves any rate for now – or rate credit for at this point.

Now, you have to do those things as an organization, because in order to get the inflection point to make our capital more efficient, you have to be willing to take that risk and do that in the near-term, because we firmly believe one or more of these opportunities that we’re pursuing is actually going to show to be even more capital efficient, have lower F&D costs and help us reduce our maintenance even more. So, I look at it, if we just want to say, hey, look what’s the base business maintenance capital? We think for this year it’s probably now around $500 million. And honestly with some of these changes that we’re making, we hope to drive that down into, say, the $450 million or low-4s with time.

And as you drive that maintenance capital level down, then you get to the point where that EBITDA generation increase, you’re actually moving towards cash flow neutral after paying interest and G&A. Our G&A run rate is also down year-over-year as well. So, that also helps. Now, in addition, Kyle’s comment is exactly right. In addition, in any good oil and gas company we’re looking for, we always want to look for accretive A&D. That may be 640-acre leases that we’re taking and bolting and blocking in to some of our best acreage, or it may be more transactions like you saw us just execute. But we believe with the combination of them, then you’ll start to see that that debt to EBITDA ratio come down, and that’s how we’ll get to free cash flow neutrality.

Q: And then, my follow-up is with regards to capital allocation between the plays. You’ve talked about some of the improvements that you’re seeing in the Eagle Ford. What would you need to see positively or negatively and what is the scope for further shifts or increases in capital between the Eagle Ford and the Permian in particular?

President and CEO Russell E. Parker: Well, we need to see these new tests, and it’s going to take us about six months really between testing the new zones and seeing what our completion designs do. And also with the infrastructure gains that we’re making in the Permian, we think that’ll give it a little bit of a leg up on the Eagle Ford possibly going forward. But ultimately, what it’s going to come down to is as we test these new ideas and this just gets to our core business properties, right, you got to innovate, execute and then evaluate, we go back – and we evaluate every month, by the way. Every month, we would roll off projects and we roll on projects to see how we’re doing from a F&D standpoint, rate of return standpoint, and dollars per BOE a day standpoint. And then right now, we haven’t seen enough to change the allocation. But I would anticipate as we go through the year and we get these results, we will probably see things that would change that project list to sort differently, right, and then we’ll reallocate capital as per the results.



January 19, 2018

SLB: says will exit seismic acquisition market; posts almost a billion-dollar write down for Venezuela

Schlumberger Limited (ticker: SLB) reported its results for fourth quarter and full-year 2017.


  • Fourth quarter revenue of $8.2 billion, increased 3% sequentially
  • Fourth quarter pretax operating income of $1.2 billion, increased 9% sequentially
  • Fourth quarter GAAP loss per share, including charges of $2.11 per share, was ($1.63)
  • Full-year and fourth quarter cash flow from operations were $5.7 billion and $2.3 billion, respectively
  • Full year 2017 revenue of $30.4 billion increased 9% year-on-year

Schlumberger Chairman and CEO Paal Kibsgaard discussed segment details in a statement

“We closed the year with fourth quarter revenue growing 3% sequentially while pretax operating income rose 9%. Sequential growth was driven by strong activity in North America, Saudi Arabia and Latin America, while revenue in the Europe, CIS and Africa Area seasonally declined. Earnings per share of $0.48, excluding charges, were 14% higher than the third quarter.

“Among the business segments, the fourth quarter revenue increase was led by the Production Group, which grew by 7%. Production Group performance was driven by strong international activity, with more than 20% sequential growth in Saudi Arabia, Russia and Argentina. In North America land, revenue grew 6% following the redeployment of additional pressure pumping fleets, despite a slight sequential decline in market activity.

“Cameron Group revenue increased 9% sequentially with growth across all product lines led by OneSubsea, on higher project volume and increased service revenue. Drilling Group revenue had more modest sequential growth of 3%, driven by strong M-I SWACO sales in Mexico and North America and increased Integrated Drilling Services activity in Kuwait. Reservoir Characterization Group revenue decreased 8% sequentially, as the seasonal decline in Wireline activity in Russia and lower revenue on a long-term project in the Middle East were partially offset by year-end sales of SIS software and WesternGeco multiclient seismic licenses.

“Pretax operating margin grew 73 basis points (bps) sequentially to 14.1% driven by improved profitability in the Production, Drilling and Reservoir Characterization Groups.

“Over the past three years of unprecedented market downturn, we have proactively sought to strengthen our technology offering and our market presence in key markets around the world, with the expansion of our hydraulic fracturing presence in North America land being the most recent example. In line with the challenging business environment over the same period, we have restructured all relevant parts of the company, in terms of size and organizational set-up, to maximize our market competitiveness and operational agility.

“Based on [our] in-depth analysis, the only product line that does not meet our return expectations going forward, even factoring in an eventual market recovery, is our seismic acquisition business. We have therefore taken the difficult decision to exit the marine and land seismic acquisition market and instead turn our WesternGeco product line into an asset-light business, built on our leading position within multiclient, data processing, and geophysical interpretation services.

3rd party E&P spend surveys predict 15-20% growth in North American investments, 5% increase in international spend in 2018: Kibsgaard

“Looking at the oil market, the strong growth in demand is projected to continue in 2018, on the back of a robust global economy. On the supply side, the extension of the OPEC- and Russia-led production cuts is already translating into higher-than-expected inventory draws. In North America, 2018 shale oil production is set for another year of strong growth, as the positive oil market sentiments will likely increase both investment appetite and availability of financing. At the same time, the production base in the rest of the world is showing fatigue after three years of unprecedented underinvestment. The underlying signs of weakness will likely become more evident in the coming year, as the production additions from investments made in the previous upcycle start to noticeably fall off. All together this means the oil market is now in balance and the previous oversupply discount is gradually being replaced by a market tightness premium, which makes us increasingly positive on the global outlook for our business,” Kibsgaard said in a statement.

“These positive oil market sentiments are reflected in the third-party E&P spend surveys, which predict 15–20% growth in North American investments in 2018, while the international market is expected to grow for the first time in four years, with a projected 5% increase in spend. So, as we enter the first year of growth in all parts of our global operations since 2014, there is renewed excitement and enthusiasm throughout our organization.”

Venezuela write-down

Given the recent economic and political developments in Venezuela, Schlumberger determined that it was appropriate to write-down its investment in the country. As a result, Schlumberger recorded a charge of $938 million during the fourth quarter of 2017.

2018 CapEx

SLB projects capex guidance for the full year 2018 (excluding multiclient and SPM investments) at approximately $2 billion, which is similar to the levels of 2017 and 2016.

US tax reform

US tax reform significantly changes US corporate income tax laws by, among other things, reducing the US corporate income tax rate to 21% starting in 2018 and creating a territorial tax system with a one-time mandatory tax on previously deferred foreign earnings of US subsidiaries. As a result, Schlumberger recorded a net charge of $76 million during the fourth quarter of 2017.

This amount, which is included in tax expense (benefit) in the consolidated statement of income (loss), consists of two components: (i) a $410 million charge relating to the one-time mandatory tax on previously deferred earnings of certain non-US subsidiaries that are owned either wholly or partially by a US subsidiary of Schlumberger and (ii) a $334 million credit resulting from the remeasurement of Schlumberger’s net deferred tax liabilities in the US based on the new lower corporate income tax rate.

After considering the impact of foreign tax credits and tax losses, the cash tax payable as a result of the one-time mandatory tax on previously deferred foreign earnings of Schlumberger’s US subsidiary will not be significant.

SLB said, “As a non-US company, Schlumberger’s corporate structure results in us largely paying taxes where we operate and earn profits, without having to incur additional layers of taxes. Given this structure, the primary impact of US tax reform on Schlumberger is that a lower federal tax rate will be applied to income earned by our US business. Absent the impact of US tax reform, our ETR would likely increase by approximately 2 to 3 percentage points in 2018 as compared to our fourth quarter 2017 ETR. However, the impact of US tax reform for 2018 is expected to largely offset this increase. As a result, we expect the full-year 2018 ETR to approximate our Q4 2017 ETR before charges and credits.

Other events

During the quarter, Schlumberger repurchased 1.6 million shares of its common stock at an average price of $64.82 per share for a total purchase price of $101 million.

In December 2017, Schlumberger announced plans to develop a state-of-the-art industrial manufacturing center at the King Salman Energy Park in the Kingdom of Saudi Arabia. The 500,000-m2 center will manufacture products for drilling, exploration, production and midstream operations. The first phase is expected to be completed in the second quarter of 2018.

On December 29, 2017, Schlumberger purchased the US hydraulic fracturing and pumpdown perforating businesses from Weatherford for $430 million. Schlumberger took ownership of Weatherford’s US-based facilities, field assets and supplier and customer contracts related to these businesses. This transaction will expand the Schlumberger OneStimSM business.

On January 17, 2018, the company’s board of directors approved a quarterly cash dividend of $0.50 per share of outstanding common stock, payable on April 13, 2018 to stockholders of record on February 7, 2018.

Full-year results

(Stated in millions, except per share amounts)
Twelve Months Ended Change
Dec. 31, 2017 Dec. 31, 2016 Year-on-year
Revenue $30,440 $27,810 9%
Pretax operating income $3,921 $3,273 20%
Pretax operating margin 12.9% 11.8% 111 bps
Net loss (GAAP basis) $(1,505) $(1,687) n/m
Net income, excluding charges and credits* $2,085 $1,550 35%
Diluted EPS (loss per share) (GAAP basis) $(1.08) $(1.24) n/m
Diluted EPS, excluding charges and credits* $1.50 $1.14 32%
*These are non-GAAP financial measures. See section below entitled “Charges & Credits” for details.
n/m = not meaningful


Q4 results

(Stated in millions, except per share amounts)
Three Months Ended Change
Dec. 31, 2017 Sept. 30, 2017 Dec. 31, 2016 Sequential Year-on-year
Revenue $8,179 $7,905 $7,107 3% 15%
Pretax operating income $1,155 $1,059 $810 9% 43%
Pretax operating margin 14.1% 13.4% 11.4% 73 bps 272 bps
Net income (loss) – GAAP basis $(2,255) $545 $(204) n/m n/m
Net income, excluding charges & credits* $668 $581 $379 15% 76%
Diluted EPS (loss per share) – GAAP basis $(1.63) $0.39 $(0.15) n/m n/m
Diluted EPS, excluding charges & credits* $0.48 $0.42 $0.27 14% 78%
*These are non-GAAP financial measures. See section below entitled “Charges & Credits” for details.
n/m = not meaningful


Consolidated revenue by area

(Stated in millions)
Three Months Ended Change
Dec. 31, 2017 Sept. 30, 2017 Dec. 31, 2016 Sequential Year-on-year
North America 2,811 $2,602 $1,765 8% 59%
Latin America 1,034 952 952 9% 9%
Europe/CIS/Africa 1,808 1,838 1,834 -2% -1%
Middle East & Asia 2,396 2,357 2,494 2% -4%
Other 130 157 62 n/m n/m
$8,179 $7,905 $7,107 3% 15%
North America revenue $2,811 $2,602 $1,765 8% 59%
International revenue $5,237 $5,147 $5,280 2% -1%
n/m = not meaningful

Conference call Q&A

Q: How should we think about the rollout of international revenue, or the contracts coming in and starting up as we go through 2018 and 2019 – and where do we see the inflection higher for international?

Chairman and CEO Paal Kibsgaard: Well, I think if you look at the progression of 2019, I think I’ll limit my comments to that. Like I said, the first quarter will be – we will see a lot of the start-up of these new contract wins. So in terms of revenue, we will have an impact of seasonality given the relative higher share of Northern Hemisphere business at this stage. And then it will be start-up cost and mobilizations that we’re going to focus on in the coming quarters.

So in terms of revenue progression, I think you will see the first quarter of significant acceleration in revenue in the second quarter followed again by a very strong growth also into the third quarter. So the year will have a somewhat slow start with seasonality, with start-up costs and mobilizations in the first and then followed by strong growth in the subsequent quarters.

Q (continued): And then with respect to the first quarter, normally, there’s about a 10% decline or so for Schlumberger’s earnings, yet that’s in a normalized year where you have a lot of back-and-forth quarter sales and so you see the drop-off there.

Should we think about something in that range or will it be maybe more of a pronounced decline at 1Q and then more of a jump in 2Q because of the staging and the preparation?

Kibsgaard (continued): Yeah, I think from an overall activity standpoint, I mean, we – I think about a 10% reduction in EPS is a good benchmark for that. On top of that, we will have, I would say, two, three additional cents of one-time costs linked to the reactivation as well as repositioning of equipment. But I think the 10% number is a good guide for the traditional seasonality with a couple of extra cents on additional costs.

Q: What OneStim product lines are you missing and what’s the timeframe do you think you could see for that business to be built out to the way that you would like it to be a well-rounded, full-product suite?

Kibsgaard: Yes. So for the multi-stage completion business for U.S. land, we do have a more or less complete offering. There are a few small pieces that were missing that we have, we’re working on organically. But in terms of overall, we have the products that we need in the market. We have a presence in the market, although it is not very high.

So what we are in full swing of doing now is to step up both supply chain and manufacturing as well as sales of this offering and you will now tie this very closely to the deployment of additional horsepower, which we obviously have ramped up significantly already in 2017.

So we have a very aggressive growth plan for the multi-stage completion offering that we already have in-house and we will look to penetrate significantly into the OneStim frac fleet that we already have in operation as well as the additional fleets that we will put into play in 2018.

Q: We’ve started to receive a few questions from investors regarding what is Schlumberger’s main growth strategy from here, what are the main initiatives to execute on that growth strategy?

I think it would be useful if you just, for a minute or two, from a high level, if you could briefly discuss the overarching strategy of the company going forward and the key initiatives to execute on that strategy?

Kibsgaard: Well, I would say that if you look at what we’ve done over the past three years in the down cycle, we have through acquisitions, in particular, Cameron, and through the combined, I would say, a number of small acquisitions within land drilling and organic investments, we have increased our addressable market with around 50%.

So we have now a very complete portfolio within Reservoir Characterization, within all aspects of Drilling, within all aspects of Production, with an increased presence in U.S. land as well and we’ve added Cameron to the lineup in 2016.

So our strategy going forward is very clearly that we want to now increase our market share, increase our participation in all aspects of the global business. We have a fantastic presence in the international market, which are now just returning to growth.

So our strategy is very clear, it hasn’t changed. We will continue to participate in all the major markets around the world and we are very excited about the growth opportunities now that international is providing us and again, the earnings power we have in these markets.

Q: Could you speak to the expected cadence of deployment and reactivation of the Weatherford frac fleet over the 2018 timeframe and then moreover, if you could also speak to what you expect the total reactivation cost of the fleet to be as well and whether you expect all 20 of these fleets to be working by the culmination of the end of this year?

Kibsgaard: Yes. If you look at what we did in 2017, we basically reactivated around 1 million-horsepower or slightly north of 20 fleets in 2017 of our own capacity. We are now more or less fully deployed and we had challenges early on with the reactivation and getting everything out. There’s a lot of hiring, there’s a lot of new things to take on as you massively ramp up as we did. But at least we have gotten the hang of it.

So our plan is to do exactly the same in 2018. So we would be deploying the additional 1 million-horsepower over the course of 2018 and although it’s not going to be a completely straight line, I think fairly close to a straight line over the course of the year I think is a good assumption.

Q (continued): Do you want to reveal it in terms of what you expect the reactivation cost to be?

Kibsgaard (continued): Yes. So for the horsepower that we bought from Weatherford, we expect the total reactivation cost to be in the range of $100 million, which is factored into our CapEx guidance.

November 2, 2017

Borrowing base stays at $475 million

Unit Corporation (NYSE: UNT) reported Q3 today; highlights include:

  • Net income of $3.7 million and adjusted net income of $5.3 million.
  • Oil and natural gas segment production increased 5% over the second quarter of 2017.
  • Contract drilling segment’s average drilling rigs utilized increased 20% over the second quarter of 2017.
  • Midstream segment increased gas processed and liquids sold volumes 4% and 1%, respectively, over the second quarter of 2017.
  • Reduced long-term debt by $2.3 million from the end of the second quarter.
  • October redetermination of credit agreement borrowing base amount maintained at $475 million.
Unit Corp. Reports Profitable Quarter, Sequential Production Increase in Q3

Source: Unit Corp. September presentation

Unit recorded net income of $3.7 million for the quarter, or $0.07 per diluted share, compared to a net loss of $24.0 million, or ($0.48) per share, for the third quarter of 2016.

Total revenues were $188.5 million (45% oil and natural gas, 28% contract drilling, and 27% midstream), compared to $153.4 million (51% oil and natural gas, 17% contract drilling, and 32% midstream) for the third quarter of 2016. Adjusted EBITDA was $78.9 million, or $1.52 per diluted share, the company said.

Total production for the quarter was 4.1 million barrels of oil equivalent (MMBOE), a 5% increase over the second quarter of 2017. Oil and natural gas liquids (NGLs) production represented 46% of total equivalent production. Oil production was 6,884 barrels per day. NGLs production was 13,506 barrels per day. Natural gas production was 142.2 million cubic feet (MMcf) per day. Total production for the first nine months of 2017 was 11.7 MMBOE.

Unit Corp. Reports Profitable Quarter, Sequential Production Increase in Q3

Source: Unit Corp. September presentation

Unit’s average realized per barrel equivalent price was $20.63, a 1% decrease from the second quarter of 2017. Unit’s average natural gas price was $2.36 per Mcf, a decrease of 4% from the second quarter of 2017.

Plant outages and delays attributable to hurricane Harvey reduced quarterly production by approximately 100 MBOE, the company said. The effects of Harvey were principally due to NGL bottlenecks from fractionation plant partial shut-downs and operational delays on new wells and recompletions. After the end of the quarter, the third-party processing plant for the majority of Unit’s natural gas production in the Gulf Coast area went down due to equipment failure. The plant was down seven days before operations resumed. Cumulatively, hurricane Harvey, the Texas Panhandle ice storm in the first quarter, and third-party plant downtimes will reduce production for the year by approximately 460 MBOE.

Taking these issues into account, Unit anticipates 2017 production to be approximately 16 MMBOE.

Unit Chief Executive Officer and President Larry Pinkston said, “As is our custom, we have focused on keeping our capital expenditures in line with anticipated cash flows during the year. Much of our total capital expenditure budget is directed toward our oil and natural gas segment where we have many highly economic prospects.

“The pace at which we develop these prospects is dependent on cash flow; therefore, unexpected downtime and delays can have an adverse effect on our production.”

November 1, 2017

On October 31, 2017 Bill Barrett Corporation (Ticker: BBG) reported Q3 financial and operating results and updated 2017 operating guidance.

BBG reported a net loss of $28.8 million, or ($0.39) per diluted share for Q3. Adjusted net income for the third quarter of 2017 was a net loss of $5.9 million, or ($0.08) per diluted share. EBITDAX for the third quarter of 2017 was $47.9 million.

BBG said it had 26% sequential production growth, 33% sequential growth in oil volumes, tighter oil differentials, an 18% sequential decrease in LOE, and capital spending that was below guidance. BBG said it anticipates 2017 production growing over 20% relative to 2016 and it expects to generate greater than 30% growth in 2018.

Debt and Liquidity

The company reported that at September 30, 2017, the principal debt balance was $677.4 million, while cash and cash equivalents were $155.9 million, resulting in net debt (principal balance of debt outstanding less the cash and cash equivalents balance) of $521.5 million. Cash and cash equivalents were reduced subsequent to the end of the quarter as BBG made a regularly scheduled interest payment in October 2017 of approximately $14 million related to its Senior Notes due 2022.

CAPEX: spud 26 XRL wells in Q3, completed 19 XRLs

Capital expenditures for the third quarter of 2017 totaled $56.8 million, which was 19% below the midpoint of BBG’s guidance range of $65-$75 million. Lower than anticipated capital expenditures were primarily the result of improved drilling and completion efficiencies that have offset service cost increases. The company operated two drilling rigs for the quarter and spud 26 extended reach lateral (“XRL”) wells in the DJ Basin. Completion operations were conducted on 19 XRL wells.

Operational Highlights

DJ Basin

BBG produced an average of 18,508 BOEPD in the third quarter of 2017, representing 28% sequential growth. Eleven XRL wells were placed on initial flowback during the third quarter and two drilling rigs are currently operating in the basin. BBG continues to see improving well results from its enhanced completion program that has evolved to include approximately 1,500 pounds of sand per lateral foot and frac stage spacing of approximately 120 feet. In addition, the company incorporated modifications to its choke management program on recent drilling and spacing units (“DSU”) that are anticipated to result in peak production being achieved earlier in the production cycle.

The company continues to achieve drilling and completion efficiencies on its XRL well program that have resulted in a 28% average year-over-year improvement in 2017 cycle times leading to increased stages completed and pounds of sand pumped per day. This has been primarily achieved through a 37% improvement in the number of frac stages completed per day and a 27% reduction in the number of days required to drill out frac plugs.

Drilling and completion costs for XRL wells drilled during the first nine months of 2017 have averaged approximately $4.7 million per well, which includes the cost of incorporating higher proppant concentrations and tighter frac stage spacing.

Unita Oil Program

Production sales volumes averaged 2,333 BOEPD (91% oil) during the third quarter of 2017. The oil price differential averaged $2.41 per barrel less than WTI as new marketing contracts became effective on May 1, 2017.

BBG has commenced a marketed sales process to divest of its Uinta Oil Program assets and, if successful, it is anticipated that a sale would be announced in the fourth quarter of 2017.


The following table summarizes our current hedge position as of October 30, 2017:

Oil (WTI) Natural Gas (NWPL)
Period Volume
4Q17 8,125 57.69 10,000 2.96
1Q18 8,750 52.88 5,000 2.68
2Q18 8,750 52.88 5,000 2.68
3Q18 7,000 52.00 5,000 2.68
4Q18 7,000 52.00 5,000 2.68
1Q19 1,750 50.54
2Q19 1,750 50.54
3Q19 1,750 50.54
4Q19 1,750 50.54





Q&A from BBG Q3 conference call

Q: You’ve mentioned in the release and, Scot, you talked about the choke management program, particularly adjusting the chokes, and I’m assuming opening the chokes a little earlier than you used to. Can you talk about peak production for a well previous and what it is now and have you seen any change to the declines in the outer months?

CEO and President R. Scot Woodall: So really the changes really have just occurred on the last two pads, which are the most west pads that we have that are over there, I believe, at 62 or 63 – 63 West. And the intent would be that we would reach peak production, say, in month three where I guess we typically would see that probably in months five or six. And so the two previous pads to the western pads were up in the north and we kind of started getting a little bit more aggressive with the chokes kind of halfway through those flowbacks.

So they might be a month earlier, but really it really is going to take place on the two pads that have been online for maybe about 45 days thinking that they would reach peak production in about three months. It’s still early to see since those are the first two pads, obviously we don’t see a decline yet, so it’s probably a little early to comment on if there is an impact to decline rates or not. But just from what early indications of what we did on the north and these two western pads, seems like we’re trending in the right direction.

Q: You also mentioned the average well cost of $4.7 million. Is that currently where costs are still and are you all seeing any inflation kind of hit the numbers yet?

R. Scot Woodall: No. That’s probably what we averaged in Q3 and we expect the same number in Q4 and so we think that we’ve been able to mitigate any cost inflation pressures by the drive and the efficiencies that I mentioned. That $4.7 million does reflect the 1,500 pounds of sand per lateral foot and the 120-foot stage spacing.

Q: Relative to the completions, could you discuss what you’re thinking for next year in completion changes or do you really want to run what you have now through most of the year and then think about altering any completion design in 2019?

R. Scot Woodall: I think for the most part, we’re comfortable with where we are. We need to see a few more months of data. If anything, maybe there’s one more stair-step of sand going from 1,500 pounds to maybe 1,700 pounds, but we need to probably see some data before we make that decision. So I think right now we’re kind of executing on the 1,500 pound and the 120 foot stage spacing in the wells that we’re completing now.

Q: You talked about the efficiencies quite a bit on the call and they’ve been great. As you look in the 2018, there’s nothing formal yet but a two-rig program would be a lot of wells. Just how do you see kind of triangulating your spending and activity around what the efficiencies you gained on the two-rig program?

R. Scot Woodall: You’re right, because probably we’re in that 50 to 55 wells growth per rig. So if you run two rigs, you’re probably more than 100 wells. So I think some of the drivers, as we think about 2018, will be where commodity prices sit, as we try to balance cash flow and spending, and also what are the proceeds from Utah and we consummate that deal, and looking at that to help drive some of the 2018 funding. So, provided that goes as we plan and we see some positive bids in the next couple of weeks and actually get that deal close by year-end, probably will drive spending levels for 2018.

Q: In regards to the LOE, we saw the DJ come down nicely this quarter to about the mid $2 range. Is that a good run rate going forward or is there anything in there that impacted it this quarter? How are you thinking about that as we head into next year?

R. Scot Woodall: It’s probably a pretty good run rate. Obviously Q4 and Q1 are sometimes a little higher just to the weather in the Rocky’s, but I think probably on an overall basis for the year, it’s probably a pretty good run rate.

Q: A completion job tested stage spacing as tight as 100 feet with 95 stages. However, the three DSUs that have been placed on flowback more recently all incorporate slightly wider spacing with 120 feet with 82 stages. Can you provide some color on what prompted this design tweak?

R. Scot Woodall: I think we over the last year or two have tried to tweak just a couple of wells on a drilling spacing unit and then looked at the results and then that would drive how we do the future completions. So you’re right. We tested a 100-foot stage spacing in a couple of DSUs and we’re really waiting on those results. And so, going forward, we’re doing 120 feet, we’ll see if the 100 feet ends up having a cost/benefit analysis associated with it, and then maybe we’ll go to the 100 feet or stay at 120 feet. So it was just a data point that we wanted to go collect.

Q: You mentioned over past or over the first nine months of 2017 that completed well cost of average $4.7 million per well on average, which includes the costs of incorporating higher proppant volumes and tighter stage spacing. So directionally, what percentage of the cost saving realized to-date do you believe are due to self-help versus market? What percentage do you believe will carry over to the 2018 program?

R. Scot Woodall: Service costs have clearly gone up. And so I think we’ve been able to kind of keep those a little bit more in check by the efficiencies. So from an overall well cost of $4.75 million, we probably have experienced a 10% or 15% inflationary number with that well cost and probably have mitigated half of that or so through the efficiencies.

Q: If we could just revisit the choke management question, how much production history will you need from the two western pads to conclude whether the decline rate has changed? And as a follow-up to that, what’s the risk if the decline rate gets deeper from opening up the choke and the business itself becomes more capital intensive?

R. Scot Woodall: Probably, we need to see six months after peak production. So if we get to peak production in three months, you probably want to see at least three months of history or so before the engineers get comfortable of what that decline rate looks like. Obviously, this is something that the engineers look at pretty hard, and so this is kind of a minor step change. I don’t think it’s a very aggressive step change. So I think we feel pretty comfortable in what we’re doing. But as always, when you tweak something, you got to do a post appraisal of it.

Q: As you drill some wells south of the river here in the first half of 2018, are there any expectations on how those wells might look compared to the central or northern acreage?

R. Scot Woodall: Probably in line, I would guess. I don’t think we’ve really varied our expectations too much geologically. We like it. We think that the Niobrara C thickens up and so probably our G&G organization would put a little bit of a tick-up in terms of expectations. The engineers are always conservative. So we’re probably running with the same expectations that we have kind of on the central acreage position and we’ll see. I said we’ve been down there with two rigs, we’re drilling a number of wells now, and all those completions will take place kind of at the end of the year and then into the first quarter a little bit.

Q: In 2018, Is your goal to try to pick up some more acreage and potentially use the Uinta proceeds for that or would you just prefer to use the Uinta proceeds to fund the outspend for next year?

R. Scot Woodall: Clearly, we like the basin. So I think we’ll look at other opportunities. And so our land group and geology group are always reviewing land opportunities just to kind of bolt on. So it’s kind of a normal course of business, I guess I would say, and we’ll see what opportunities present themselves. You’re right, the Utah proceeds could help in that matter, but probably targeting more towards funding the D&C capital program is what I would think first.