Recent Company Earnings:


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.

Hedging

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

Oil (WTI) Natural Gas (NWPL)
Period Volume
Bbls/d
Price
$/Bbl
Volume
MMBtu/d
Price
$/MMBtu
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.

 

October 20, 2017

Kibsgaard: Market is now in balance, look for upward movement in oil prices and growth in E&P investment 

Earnings season is here for Q3, and the oil and gas industry got off to a strong start with Schlumberger (ticker: SLB) reporting today.

Q3 Stats

  • Revenue of $7.9 billion increased 6% sequentially
  • Pretax operating income of $1.1 billion increased 11% sequentially
  • GAAP EPS, including Cameron integration-related charges of $0.03 per share, was $0.39
  • EPS, excluding Cameron integration-related charges, was $0.42
  • Cash flow from operations was $1.9 billion; free cash flow was $1.1 billion

 

(Stated in millions, except per share amounts)
Three Months Ended Change
Sept. 30, 2017 Jun. 30, 2017 Sept. 30, 2016 Sequential Year-on-year
Revenue $7,905 $7,462 $7,019 6% 13%
Pretax operating income $1,059 $950 $815 11% 30%
Pretax operating margin 13.4% 12.7% 11.6% 66 bps 178 bps
Net income (loss) (GAAP basis) $545 $(74) $176 n/m 209%
Net income, excluding charges and credits* $581 $488 $353 19% 65%
Diluted EPS (loss per share) (GAAP basis) $0.39 $(0.05) $0.13 n/m 200%
Diluted EPS, excluding charges and credits* $0.42 $0.35 $0.25 20% 68%
*These are non-GAAP financial measures. See section entitled “Charges & Credits” for details.
n/m=not meaningful

 

Schlumberger Leads Off Q3 Earnings Rush

Schlumberger Leads Off Q3 Earnings Rush

Schlumberger Chairman and CEO Paal Kibsgaard said that the company’s “activity growth in the third quarter was again led by our North America Land GeoMarket, where we continued to gain market share in both hydraulic fracturing and drilling services despite the decelerating rig count growth.

Kibsgaard said the company saw sequential activity growth in Russia, the North Sea, and Asia, while activity in the rest of the world was largely flat compared with the second quarter.

“From a technology standpoint, revenue growth was driven by the Production Group, which increased 15% sequentially from continued share gains in the hydraulic fracturing market in North America land as well as from increased unconventional resources project activity in the Middle East.

“Reservoir Characterization Group revenue increased 1% as strong Wireline activity in Russia and the North Sea was partly offset by lower exploration-related activity for WesternGeco.

“Cameron Group revenue increased 3% driven by higher product sales for Surface Systems in North America land. Drilling Group revenue grew 1% as we remained sold out on PowerDrive Orbit* technology in North America land and completed key Integrated Drilling Services (IDS) projects in Mexico and Iraq that will not resume until early 2018.

“Geographically, North America revenue increased 18% as we continued the high redeployment rate of our spare hydraulic fracturing capacity. North America land revenue grew 23% sequentially, significantly outpacing the 12% increase in rig count, with hydraulic fracturing revenue growing 42%. Over the past six months, we have more than doubled the number of active fracturing fleets in North America land and have now redeployed almost all available capacity.

Outlook for GOM remains ‘bleak’

“In the US Gulf of Mexico, activity continued to weaken in the third quarter, and the outlook remains bleak for this region based on current customer plans.”

Oil market is now in balance

“The reduction in global oil inventories in the third quarter is clearly showing that the oil market is now in balance, which is reflected in the upward movement in oil prices over the past month,” Kibsgaard said.

Kibsgaard said this was supported by the following positive signs:

  • First, the investment appetite in North America land now seems to be moderating, driven by a growing focus from E&P companies on financial return and the need to operate within cash flow rather than the pursuit of production growth.
  • Second, comments from several of the key OPEC Gulf countries, as well as from Russia, suggest that an extension of the existing production cuts beyond the current nine-month agreement is a possibility.
  • Third, investment levels in the production base outside North America land, OPEC Gulf, and Russia all remain at unprecedented low levels, raising the likelihood of a medium-term global supply challenge, and increasing the urgency for higher investment.

Expect further upward movement in oil prices and growth in E&P investment

“A continuation of these market trends, combined with further steady draws in global oil inventories is now creating the required foundation for further upward movement in oil prices and subsequent growth in global E&P investment.

“And while there is still some level of uncertainty around the exact timing of this industry recovery, we see a number of market factors and data points now emerging that make us increasingly positive and optimistic about the outlook for our global business. It is also worth noting that the geopolitical risk premium on the oil price, which was quite significant in the past, has been replaced in many ways today by an oversupply discount. Given the visible tightening of the supply and demand balance and the current geopolitical tensions in many of the world’s key oil producing regions, a geopolitical risk premium may again become a significant factor,” the CEO of the largest oilfield service company said.


From the SLB Q3 2017 conference call Q&A

During the earnings call Q&A, Kibsgaard was asked about performance based drilling contracts.

Paal Kibsgaard: Obviously, performance-based drilling contracts has been established on land for quite a long time. And we see that the next, I would say, area that this will start to grow in is in shallow water. If you want to drill performance-based, you need to have a pretty good handle on the subsurface and the drilling rigs. And given the drilling activity that you’ve had historically on shallow water, this is, again, why we see this as the next horizon that these – the contracts will take on. So in terms of customers, we have a range of customers who are already pursuing performance drilling contracts offshore on shallow water.

The main thing is that these contracts traditionally has not included the rig. So what we’re seeing now is several customers are trying to bring the rig into play and our rationale for investing in Borr is generally to get closer to one of the rig providers to try to drive this new behavior and establish performance contracts including the rig.

Now our relationship with Borr does not preclude us from having similar relationships with all the other jack-up providers and we have engagement and discussions with several of them to do exactly the same there.

So I would say it’s a growing interest from the customer base. We have several key customers who are already well advanced in trying to establish this. And the main thing is that we need the directional drilling company and all the other well construction services related on the rig, together with the rig provider to come together and establish a contracting framework that is benefiting all parties involved. And I think that’s what we are trying to drive through our initial investment in Borr.

Q: It does break with the traditional way of contracting, very much so. To what extent customers are really opening up to that type of debate.

Paal Kibsgaard: Yes. I think it’s fair to say that several key customers, I think, are happy to never see rig day rates again. If they can get the entire drilling package, including downhole and surface onto performance-based, I think that would be a benefit both for the customer and for the service companies involved.

Q: We’ve been asked this by a couple of investors. Does the latest Canadian SPM investment in terms of what you’ve done and what you’re talking about doing, does that diminish the likelihood or magnitude of buybacks or dividend increases going forward?

Paal Kibsgaard: Well, I would say on the way we have always planned to use our cash, the priority has always been to reinvest into the business, into projects and activities that are driving earnings and that are accretive to our returns. Beyond that, we’ve said that we will review dividends on an annual basis and the balancing factor will always be buybacks. Nothing has changed to this effect and we will review dividends in January and we will continue to be in the market to buy back stock. But we won’t buy back stock at the expense of not being able to do what we think is right in terms of driving the growth of the underlying business.

Simon Ayat, SLB: Let me add one thing about the Canadian project. The maximum cash exposure that we have announced, which is basically the amount we’re going to pay upfront, it is a maximum cash exposure. Any future investment in the project will be mitigated by the cash flow that we will generate from the production of the project itself. So just to make it clear, the future investment in Torxen will be basically self-sufficient from the production that we’re going to generate from the project itself.

Q: Following up on Bill and Scott’s question around SPM, when we think about SPM, kind of in U.S. onshore, do you – are you trying to take advantage of excess service capacity or is it more about kind of better penetration of technology? And if it’s the latter, what technology do you think you’re able to exploit through SPM that you’re not through your traditional businesses?

Paal Kibsgaard: I would say in U.S. land, it’s generally looking to basically demonstrate what our technology and capability sets can generate, right? So this is all the way from well placement, drilling efficiency, frac placements and also overall how we complete these wells. So most of these things we have generally talked to all our customers about already. The main thing is the ability to put this together into consistently delivering top quartile wells, which, I think we’ve demonstrated through the example that Patrick described today with SM Energy. So we’re just looking to do more of that. And that could be in the form of SPM. But like I said earlier, it could be in any form of whatever contractual engagement our customers are looking for.

 

August 11, 2017

During its second quarter, Superior Drilling Products (ticker: SDPI) reported revenue of $4.0 million, up from $2.9 million in the previous year’s Q2. The company’s net income was $0.3 million for Q2, up $3.4 million from a Q2, 2016 loss.

The company’s Drill-N-Ream®—or DnR—technology increased in sales and the company said that its channel partner successfully achieved its June 2017 market share goal with the DnR. Revenue from the company’s tool sales increased to $2.5 million—an increase of 179% over its prior year period.

The company’s contract services were $1.6 million—reflecting an increase of 601% from Q2, 2016.

Looking into the future, Superior noted that it intended to expand its global reach with channel partners. The Q2 update said that Superior was discussing the addition of the company’s completions system tool—the Coiled Tubing Strider—to channel partners’ inventories.

Superior Drilling Products will be a presenting company at the upcoming EnerCom conference in Denver, Colorado—The Oil & Gas Conference® 22.

The conference is EnerCom’s 22nd Denver-based oil and gas focused investor conference, bringing together publicly traded E&Ps and oilfield service and technology companies with institutional investors. The conference will be at the Denver Downtown Westin Hotel, August 13-17, 2017. For details please visit the conference website.

179% Increase in Tools Sales for Superior Drilling Products’ Q2 Update

Two companies, Eco-Stim Energy Solutions and Bellatrix Exploration, that are presenting at EnerCom’s The Oil & Gas Conference® have announced Q2 earnings and updates.

Eco-Stim Energy Solutions

Eco-Stim Energy Solutions (ticker: ESES) announced during its Q2 earnings call that is had increased its revenue by 233% over Q1, 2017 to $8.5 million. The company signed a second contract for services in Oklahoma, allowing it to expand its operations and activate a second spread.

The company completed a total of 88 stages during Q2 and—during July—completed another 85 stages in Oklahoma. In its Argentina operations, Eco-Stim completed 53 stages during Q2, with another 23 in July. The company will also be acquiring approximately 45,000 HHP worth of fracturing equipment for its two contracts.

Eco-Stim also reduced its long term debt by $41 million and its capital expenditures for the second quarter totaled approximately $4.2 million. The company’s capital expenditures were related to adding additional pressure pumping equipment to the company’s assets.

Bellatrix Exploration

During its second quarter, Bellatrix Exploration (ticker: BXE) reported an average quarterly production of 37,916 BOEPD—representing growth of 9% over its previous quarter. The company exceeded its mid-point estimate of 34,500 BOEPD.

Bellatrix decreased its debt by $52.8 million—down to $382.6 million as of June 30, 2017. The company’s capital expenditures for the first half of the year were $55.2 million, in line with its estimates. The company’s Q2 capital expenditures totaled $11.2 million. During the second quarter, the company drilled two gross (1.2 net) wells in the Spirit River formation.

As of the earnings call, the Alder Flats Plant Phase 2 expansion was proceeding on time, according to Bellatrix. The expansion is intended to increase the plant’s capacity to 230 Mmcf per day—more than doubling it from 110 Mmcf per day. The expansion is expected to be finished by early Q2, 2018.

The company increased its full year guidance to 36,000 BOEPD, up from 34,500 BOEPD announced in late June. Bellatrix maintained its full year capital budget of $120 million. For the remainder of 2017, Bellatrix expects that it will drill another 13 net wells.

Bellatrix Q2, 2017 Earnings Call Q&A

Q: You mentioned you had 15 years of drilling inventory. What steps are being taken in the Spirit River to make sure that that inventory is expanding over time? Are you looking at adding more land or you finding success in different zones within the Spirit River that could help that part?

Brett Eshleman, president and CEO: Yeah, pretty much Jay, all of the above. We continually as we do every year to add more land, usually the question is, you don’t see that in the marketplace, because it’s all done a section here, a couple of sections over there, it’s always done primarily on the smaller basis, it’s we’re always continuing to add, maintain or grow that inventory. I mean, we always look at these opportunities, but as you know, it’s – those are fewer and farther between.

For us, since I’ve always found that when you control your own backyard and you put it in the infrastructure and you have egress and you control everything in there, when opportunities arrives people come to you, whether that’s to sell some land to you, whether that’s to farm out some land. Our inventory is always drilling, and then also with additional zones. I mean, we primarily only been focused in our backyard right now, because we have such a plethora of

inventory, and we’ve really proven it up is in the Spirit River and most notably in the Spirit River not [indiscernible] and flare a and flare b, we have a cluster of other inventory and kind of the lower [ph] mantel just underneath the Spirit River, whether you went to the [indiscernible] you know not even to get into the Cardium inventory that we have that we’re not putting much any on the couple of nice oil wells this year. We drove one in the first quarter this year that hit you know the top 10 oil wells drilled.

These – and we look at all the other zones, you know from Rock Creek and Viking. So we don’t even talk about those, so those are life time of inventory through this area and that’s one of the reasons why you know the Deep Basin is such an attractive area for industry players.

You have all those several zones, I mean down in the basement, you’re not even getting into the Duvernay, which you know continues to be unlocked and someday will be a huge resource shale play that is profitable and growing. So no, the inventory we are always on that always looking to increase inventory and expand the different horizons.

Eco-Stim Energy Solutions and Bellatrix Exploration are presenting at EnerCom’s The Oil & Gas Conference® 22

ESES and BXE will be presenting companies at the upcoming EnerCom conference in Denver, Colorado—The Oil & Gas Conference® 22.

The conference is EnerCom’s 22nd Denver-based oil and gas focused investor conference, bringing together publicly traded E&Ps and oilfield service and technology companies with institutional investors.  The conference will be at the Denver Downtown Westin Hotel, August 13-17, 2017. To register for The Oil & Gas Conference® 22 please visit the conference website.

August 10, 2017

41 Gen 3 wells on line in the Eagle Ford

In its Q2, 2017 earnings call WildHorse Resource Development (ticker: WRD) reported second quarter production of approximately 22,600 BOEPD—which was 28% higher than its average production in Q1, 2017. It achieved a net income of $25.9 million, or $0.28 per share.

Drilling activity

During the course of Q2, the company brought 18 gross (17.4 net) wells online in the Eagle Ford, one gross (1.0 net) well online in the Austin Chalk, and two gross (1.1 net) wells online in north Louisiana. The company’s Eagle Ford rigs averaged 13.2 drilling days in Q2.

Eagle Ford Developer WildHorse Scores 28% Higher Production, Brings in 2,387 BOEPD Austin Chalk Well

Source: WildHorse

The single Austin Chalk well was WildHorse’s first well drilled into the formation, which showed a 30-day initial production of 2,387 BOEPD. Because of the success of this well, WildHorse noted that it would continue delineating its Austin Chalk assets with new wells in the remainder of the year.

WildHorse said that, as of the Q2 update, it now had 41 Generation 3 wells online in the Eagle Ford.

The company expects to bring another 60 wells online in the Eagle Ford during the second half of 2017. WildHorse added a second rig to its Louisiana acreage during Q2. Both rigs are drilling two separate 3-well pads—which will be brought online during Q4, 2017.

Finance

WildHorse also closed a $594 million acquisition of 111,000 net acres in the Eagle Ford during the quarter. As of Q2, 2017—the company was operating the second largest Eagle Ford area. Its borrowing base on its revolving credit facility was raised from $450 million to $650 million.

Eagle Ford Developer WildHorse Scores 28% Higher Production, Brings in 2,387 BOEPD Austin Chalk Well

Source: WildHorse

The company reported an increase in lease operating costs to $3.33 per BOE in Q2, 2017, up from $1.73 per BOE in Q2, 2016. WildHorse attributed the increase to higher lease operating costs out of its Clayton Williams acquisition in December, 2016. Company continues to build efficiency in the area, reflected by a quarter-to-quarter decrease from $4.37 per BOE in Q1 to $3.33 per BOE in Q2.

WildHorse anticipates that its lease operating costs will be impacted by the Anadarko/KKR acquisition, which will come in with higher legacy lease operating costs of between six and seven dollars per BOE. Despite this, the company estimates that its full year LOE will be within its full year guidance of $3.25 and $3.75 per BOE.

WildHorse spent approximately $11.5 million in exploration during Q2, up significantly from its exploration expenses in Q2, 2016—which totaled $0.1 million. The increase in exploration expenses were attributed to undeveloped leasehold impairments, totally $9.9 million, and $1.5 million in seismic acquisitions.

The company’s drilling and completion costs were $182.2 million for the second quarter, which brought the year-to-date total to $267.6 million. Approximately 90% of the drilling and completion capital was allocated to the company’s Eagle Ford acreage, with the remaining 10% allocated to its northern Louisiana acreage.

Looking forward

WildHorse decided to keep its 2017 operational and financial guidance—which was given on May 11, 2017. The company expects its production fall with the range of 27,000 to 31,000 BOEPD. Its capital expenditure guidance was between $550 and $675 million.

Over the course of the year, the company expects to spud a total of between 100 and 120 gross wells, and complete between 85 and 105 gross wells.

WildHorse Resource Development is presenting at EnerCom’s The Oil & Gas Conference® 22

WildHorse will be a presenting company at the upcoming EnerCom conference in Denver, Colorado—The Oil & Gas Conference® 22.

The conference is EnerCom’s 22nd Denver-based oil and gas focused investor conference, bringing together publicly traded E&Ps and oilfield service and technology companies with institutional investors.  The conference will be at the Denver Downtown Westin Hotel, August 13-17, 2017. To register for The Oil & Gas Conference® 22 please visit the conference website.

WildHorse Q2, 2017 Earnings Call Q&A

Q: On the Austin Chalk Well, could you talk about the cost perhaps lateral length completion design and how many wells are being planned for back half of the year?

WRD: Several questions there. Cost, we’re not releasing any specifics guidance on ranges. Obviously, there’s going to be a number of variations in the first few wells that we drilled, so I don’t want to lay a number out there and then the next one be materially different. But we’re kind of roughly saying $7 million to $7.5 million for an Austin Chalk Well. As far as completion design is concerned, it’s roughly in line with the way we’re completing the Eagle Ford well, but we all recognize it’s the different reservoir. So, that may merely represent a starting place. And so, we would expect to be continue evolution on how we hone in on the best way to complete those wells.

And at this point, we don’t have a fixed number of additional loss in Chalk well that we planned to drill this year. I think we talked about we have drilled the second Austin Chalk well and it is in early flow back right now and the results look encouraging. It is not in Washington County, it’s in Burleson County, but we’ll continue to work on potential locations. And as we’ve indicated thus far, we’ll continue to delineate the Austin Chalk position.

Q: In the Austin Chalk I know you only have one well, but I was curious how the current iteration of the Chalk play ties to the old fractured carbonate play. In other words, do you want to go toward fractures or stay away from fractures, and does that add a layer of complexity when you think about completing and the predictability of the reservoir?

WRD: I would say the short answer is it may be too early to tell. But if you look at it from a high-level perspective, obviously, the early development of the Chalk back in the 1980s and 1990s, most of the good results and, obviously, most of the activity was focused on where it was naturally fractured because that was what enabled the hydrocarbon to flow to the wellbore.

We may be seeing an opportunity now to generate our own fractures in the reservoir because of the current fracture technology that we employ. And so, that may be much less of a driver going forward as to whether there is a lot of natural fractures in the Chalk at that particular location.

Gradiant Energy Services tailors water solutions to basins, plays, operators

Water is a major concern throughout the oilfield. Operators are struggling with the logistics of water treatment as the need to handle water in day-to-day oilfield activities grows.

Gradiant Energy Services is a privately held company that offers several solutions geared towards bacteria treatment, re-use, disposal, and desalination of water resources.  Gradiant is a presenter at EnerCom’s Oilfield Tech & Innovation Day on Aug. 17 in Denver.

Providing water service in areas of large demand

“Gradiant has a strong patent portfolio, with over 60 patents surrounding water technologies throughout the client’s value chain,” Danny Jimenez, Gradiant CEO told Oil & Gas 360®.

Jimenez said the industry is increasingly moving—by choice and by regulatory necessity—to a place where water is recycled, especially at a time in the industry where frac intensity is growing fast.

Longer laterals and bigger fracs drive need for water recycling and disinfection

Jimenez said the move toward longer laterals, more stages, and more fluid volume has created more demand for water recycling, as well as for water disinfection technology. Gradiant is also looking beyond near-term demand for water technology—past the demand arising from increased fracturing intensity.

Jimenez said that over the long term “the industry is going to be faced with more constraints in water disposal, and our technologies have a lot of application in that area,” Jimenez said.

All water is not the same

In talking about its treatment designs, Jimenez said that “waste-water and produced-water varies from place to place and from client to client, and has an incredible component of variability.”

“We are in a place where we can design, own and operate treatment facilities to meet a clients’ specific needs. Our technology allows us to be very flexible.”

Gradiant Energy Services – an EnerCom Oilfield Tech & Innovation Day presenter

Gradiant Energy Services is a featured innovator that is presenting its technologies at EnerCom’s Oilfield Tech & Innovation Day Aug. 17, 2017 at the Denver Downtown Westin hotel.

EnerCom’s Oilfield Tech & Innovation Day features large and small companies that have new technologies designed to benefit the oil and gas industry by boosting production levels; lowering finding, drilling, completion and production costs; enhancing well integrity and community relations; plus other economic improvements made possible by new technologies that are in use or in field tests in the world’s oilfields.

Who should attend Oilfield Tech & Innovation Day?

Drilling and completions engineers, VPs of drilling and development, drilling managers, geologists, petrophysicists, petroleum engineers and chief operating officers from E&P companies and oilfield service and technology firms, plus energy venture capital investors and private equity investors.

To register to attend EnerCom’s Oilfield Tech & Innovation Day, please visit the conference website registration page.

EnerCom’s Oilfield Tech Day: All Water is Not the Same

August 9, 2017

Four presenters at EnerCom’s 22nd The Oil & Gas Conference® announced earnings and operational updates for Q2.

Northern Oil and Gas

Northern Oil and Gas (ticker: NOG) said that its average production had grown 4% from the first quarter to the second, up to 13,794 BOEPD. The company produced a total of 1,255,280 BOE over the course of the quarter.

During the second quarter it added 4.3 net wells to production. As of the end of June, 2017 Northern had 16.1 net wells with an internal rate of return of approximately 30% at $50 per barrel pricing. At the same time, the company had leased approximately 148,571 net acres in the Williston basin and Three Forks formations. Approximately 86% of its acreage position in North Dakota—84% of its total acreage—was developed, held by production, or held by operations.

Tom Stoelk, Northern’s interim CEO and CFO, said that the company’s production was above the company’s expectations.

The company’s capital expenditures totaled $30.7 million

Northern Oil and Gas Q2, 2017 Earnings Call Q&A

Q: In terms of M&A’s Northern said that it would rather by a buyer than a seller. What kind of deal would Northern look for on the acquisition side and what factors would the company consider?

A: I think we’d evaluate it very carefully … but size would definitely be a factor with respect to it. We have had and continue to have discussions with capital providers that have suggested joint venture type things, so you might enter into a kind of sidecar sort of situation with respect to it. If the transactional size were, let’s say, $50 million or below I think we probably looked pretty hard, it probably kind to do most of it internally, possibly going to the equity market with respect to that. Equity has suffered recently obviously but I think hopefully our improved performance and what people look at the quality of really our assets, the deep inventory of wells that we have high average IRRs, really demonstrated over the period. The mix of kind of what we’re participating in is enhanced completions, which are really driving the returns in the EURs participating in.

A lot of the best wells are in the Basin. So, I think it’d be – if it were a larger size, we’d probably have to bring a partner in with respect to that.

Key Energy Services

In its Q2 update, Key Energy Services (ticker: KEG) said that its revenues in its Fluid Management service grew by 5.4% over Q1 revenues to $18.9 million. Its Coiled Tubing services revenues experienced even more growth, climbing 71.6% over Q1, up to $9.2 million.

The company’s largest, completion driven coiled tubing units experienced an increase of 110% in activity levels—as the company deployed a large-diameter unit early in the quarter. The company also experienced 17% higher pricing on the coiled tubing units.

The company divested non-essential assets for approximately $20.7 million. The majority of the assets divested were frac-stack and well testing assets, formerly within its Fishing and Rental Services segment.

Key’s president and CEO, Robert Drummond, said that Key’s customers have “allocated more of their incoming cash flows to growth-oriented new well drilling and completion rather than production maintenance spending,” and believes that, as customers’ cash flow increases “they will increase their spending on production maintenance activities.”

Midstates Petroleum

Midstates Petroleum (ticker: MPO) reported a net income of $13.7 million during Q2. The company’s production averaged 22,490 BOEPD during Q2—81% of which was sourced from the company’s Mississippian Lime acreage where it added a second rig. The remainder of the production was sourced from the Anadarko basin.

Midstates’ production was comprised of 29% oil, 25% NGLs and 46% natural gas.

During Q2, the company invested approximately $25.9 million of operating capital. Most of that capital was directed toward development in the Mississippian Lime assets. Over the course of the quarter, the company spud seven wells and put four wells on production. Midstates’ average drilling, completion and facility costs came in around $2.8 million for the first half of 2017.

The company sold non-core assets in Lincoln County, Oklahoma for $7.0 million, during July and has engaged SunTrust Robinson Humphrey in order to explore strategic alternatives for its Anadarko and NW STACK acreage. Midstates intends to transition to a Mississippian Lime pure-play company.

Penn Virginia

In its second quarter update, Penn Virginia Corporation (ticker: PVAC) announced that its production had reached 10,159 BOEPD during the second quarter—74% oil, and 8% higher than the company’s Q1 production.

The company’s net income for the second quarter totaled $21.3 million.

The company said that performance out of its Lager 3H well has exceeded company expectations, producing at a rate of 1,000 BOEPD at 70% crude oil over the course of 95 days. It also had success out of its Zebra 6H and 7H wells.

Penn Virginia agreed to purchase 19,600 net acres from Devon contiguous to its Eagle Ford acreage for $205 million—further allowing the company to drill extended lateral wells in the area. In the new acreage, the company has identified 91 gross potential drilling locations targeting the lower Eagle Ford formation, with 43 of those as potential extended reach lateral locations. The company also said that potential existed for testing in the upper Eagle Ford and Austin Chalk, in its new acreage.

Over the course of the quarter, Penn Virginia drilled seven gross (2.3 net) wells and brought seven gross (3.0 gross) wells to production in the Eagle Ford. The company began completion activities on its eight-well pad, formed by two pads—the Chicken Hawk and Jake Berger four-well pads. Penn Virginia increased its acreage to approximately 57,000 net acres through the lease or extension of approximately 1,000 acres.

Penn Virginia updated its guidance to reflect its new acquisition. The new full year production guidance was set to between 10,600 and 11,200 BOEPD, and the new full year capital expenditures guidance was set to between $140 and $160 million.

Penn Virginia Q2, 2017 Earnings Call Q&A

Q: Looking at the upper Eagle Ford and the Austin Chalk, how do you see testing those zones as we move into 2018?

A: Well, we’re currently testing two upper Eagle Ford completions on our super pad, those are two 4 well pads that are adjacent in each one of those has a upper Eagle Ford completion in them and they are offset by a lower Eagle Ford completion and in both instances for both pads, they will be traced and we’ll be able to evaluate any contribution or cross talk between the two formations, that’s an area where we’ve had some success in the past in the upper Eagle Ford.

So we’re excited to see what these will do with a slickwater completion. In terms of the Austin Chalk, that’s probably third on the list of things that we’re going to focus on, obviously being the lower Eagle Ford, the Upper Eagle Ford and then the Chalk, but the upper Eagle Ford, we do intend to test in the near future as well as probably in the 18th as well and it will probably be in co-development phase where will stack and staggered next to another one.

Northern Oil and Gas, Key Energy Services, Midstates Petroleum, and Penn Virginia Corp. are presenting at EnerCom’s The Oil & Gas Conference® 22

NOG, KEG, MPO, and PVAC will be presenting companies at the upcoming EnerCom conference in Denver, Colorado—The Oil & Gas Conference® 22.

The conference is EnerCom’s 22nd Denver-based oil and gas focused investor conference, bringing together publicly traded E&Ps and oilfield service and technology companies with institutional investors.  The conference will be at the Denver Downtown Westin Hotel, August 13-17, 2017. To register for The Oil & Gas Conference® 22 please visit the conference website.

Cimarex Energy (ticker: XEC) announced net income of $97.3 million during its second quarter conference call today—a significant turnaround from its Q2, 2016 loss of $214.4 million. The company produced near the high end of its expected Q2 guidance, with an average of 1.156 Bcfe per day—or approximately 192.7 MBOE per day.

The company’s production climbed nine percent over its Q1, 2017 production and 19% over its Q2, 2016 production. Oil production alone averaged 57,871 BOPD, an increase of 11% from its Q1, 2017 production.

Over the course of 2017, Cimarex has spent $602 million in exploration and development. During Q2, the company invested $296 million in exploration and development—with approximately $219 million of that directed to drilling and completion activities. Of that capital, 53% was directed to the Permian basin and 45% was directed to the Mid-Continent. The company funded its investments during the second quarter from its cash flow and cash on hand.

Looking forward

Cimarex has maintained its 2017 exploration and development capital allocation of $1.1 to $1.2 billion. The company expects that it will direct 62% of its capital investment to its Permian assets, with the remainder redirected to its Mid-Continent operations.

Cimarex Energy on Track for ~$700 Million Permian Spending in 2017

Source: Cimarex Energy

Cimarex anticipates that its average daily production for 2017 will be between 1.120 and 1.140 Bcfe per day, or between approximately 186.7 and 190.0 MBOEPD.  Much of its production growth will stem from expected growth in the late third quarter and early fourth quarter of 2017. Its oil production is expected to grow by approximately between 30% and 35% in Q4, 2017 over Q4, 2016.

Q2 operations

Over the course of its second quarter, Cimarex completed 51 gross (18 net) wells. Of those 51 gross wells, 11 gross (10 net) were brought to production in the Permian and 40 gross (8 net) in the Mid-Continent.

The company’s Permian production climbed 12% over its Q1 production to 644.7 Mmcfe per day. Cimarex conducted its Pagoda State four well downspacing project with 16 wells per section producing out of the Upper Wolfcamp. The four wells had lateral lengths of 10,000 feet and averaged a 30-day initial production of 1,922 BOEPD, 956 BPD of which was oil production. As of the Q2 update, the company was operating eight rigs in the Permian.

The company’s Mid-Continent acreage produced an average of 509 MMcfe per day, ten percent higher than its Q2, 2016 production. The company is in the process of delineation efforts in the Meramec play and is undergoing the completion of an increased density pilot in the Woodford formation. The density pilo consists of eight wells, testing 16 and 20 Woodford wells per section. The company believes that the test will show results in the second half of 2017. At the time of its Q2, 2017 update, Cimarex was operating six rigs in the Mid-Continent.

Cimarex Q2, 2017 Earnings Call Q&A

Q: Can you talk about the oil yield rates in the context of Culberson County, and what gave you confidence that rates will not be an issue over time?

XEC: Well, let me just take a stab at and then John or Joe may want to jump in here. Our lens is rate of return. I mean this issue was interesting but we properly modeled our response I think many of you that have followed us know we do a very exhaustive annual look back. We go back 15 years and we update the production on every well we’ve ever drilled. We update the costs, we update the commodity price file that produced into, and we update our returns. And that’s a really important exercise for us, because it levels and grounds our future decisions. And we’ve got a very confident analysis of our production history including Culberson county. Culberson county does go from oil in the reservoir to gas in the reservoir. So there are varying issues around that play, but as long as we’re properly modeling that stream, that hydrocarbon stream, rate of return is that lens and mean some into us and these are very solid outstanding rates of return. But specific to the reservoir issues, I’m going to let John or Jo either kind of…

XEC: Well, I’ll just say real quick is as Tom alluded we have a large acreage position and a multi-variable hydrocarbon system there that any one well or project we looked at has its own design GOR or yield profile. We don’t try to slap the same the yield profile or life of the well across all that acreage. We would never do that. It’s variable across acreage depending upon both the pressure, we know that the reservoir to be and the initial yield and then from there with our expectation of what that yield will do over time. And I’m very proud to say because of, like Tom said, the look backs we do, the checks we do I feel very confident and the economics presented to me is a true representation of what that well and how that well will perform both on its gas and its oil.

XEC: This is Joe. I guess how I would answer that is the phase behavior is different for all different types of hydrocarbon compositions as you know. Alluding to what Tom said is that phase behavior its characteristics will ultimately show up and how wells produce. And so for using older wells and they produce, it’s given us a DNA print of that phase behavior. Those old wells and those forecasts are what we are using to predict our new wells.

So, in our minds, we’re truly modeling the phase behavior of the reservoir, the type curves that we put together our oil, the in place calculations that we make when we perform volumetrics our oil. The recovery calculations that we come up with are based on oil. We’re forecasting an oil curve. The gas relationships to that curve, the gas becomes a secondary hydrocarbon byproduct. To the extent the GOR goes up, the well makes more gas, that the same barrels of oil that we’re forecasting. And so that is how we’re looking at it.

And the bottom line is what is those forecast for oil and gas, ultimately yield from a rate of return on our capital investment.

Cimarex Energy is presenting at EnerCom’s The Oil & Gas Conference® 22

Cimarex will be a presenting company at the upcoming EnerCom conference in Denver, Colorado—The Oil & Gas Conference® 22.

The conference is EnerCom’s 22nd Denver-based oil and gas focused investor conference, bringing together publicly traded E&Ps and oilfield service and technology companies with institutional investors.  The conference will be at the Denver Downtown Westin Hotel, August 13-17, 2017. To register for The Oil & Gas Conference® 22 please visit the conference website.

August 8, 2017

Oil & Gas Conference® presenters Lonestar, Resolute, Carrizo, Black Stone, Denbury report a busy quarter

Lonestar Resources

During its second quarter, Lonestar Resources (ticker: LONE) indicated that its production had risen by 7% above Q1 volumes. The company averaged Q2 production of 5,635 BOEPD—over its 5,266 BOEPD in Q1.

In mid-June, Lonestar closed on an approximately $110.6 million acquisition of 21,238 net acres in the Eagle Ford. The acquisition nearly doubled the company’s footprint in the Eagle Ford, jumping to 57,330 net acres.

The company announced a Q3, 2017 production guidance of between 7,600 and 8,100 BOEPD. The expected growth in production—which would be between 35% and 440% of its Q2 production—will be sourced from the new Eagle Ford acreage.

Frank Bracken, CEO of Lonestar, said in the company’s earnings call that Lonestar intends to “drill and complete [its] inventory of extended reach laterals,” which would allow the company to, “… generate production in excess of 10,000 BOEPD…in 2018.”

During Q2, Lonestar put 1.0 gross (0.5 net) wells on stream and 2.0 gross (2.0 net) wells online in its Cyclone pad. The company anticipates that, during Q3, it will add another 2.0 gross (2.0 net) wells in the Cyclone pad. Bracken mentioned in the earnings call that the 2017 drilling program was designed to hold its leases by production.

Resolute Energy

Denver based Resolute Energy Corp. (ticker: REN) indicated that its second quarter production averaged 24,355 BOEPD. Of its production, 78% was liquid and 63% was oil. The company increased its production by over 100% since the second quarter—at which time it averaged 12,490 BOEPD.

During the second quarter, the company experienced a net income of $10.7 million.

In its second quarter, Resolute spud seven wells and completed ten wells. Of those ten, four were mid-length laterals, and two were long laterals. The remaining four Q2 completed wells were DUCs. Going into the third quarter, Resolute had four wells waiting on completion, and another three wells being drilled. Resolute had a 22 well drilling plan for 2017, which it suspects it will finish in early Q4.

Because the company expects to finish its 2017 drilling program ahead of schedule, it will have the option to keep its two rigs contracted and spud up to another five wells during the remainder of 2017.

In its Bronco acquisition in the Delaware—which it closed on in May—Resolute has completed five of six DUCs. Two of the wells have indicated 24-hour initial production rates of 3,013 and 2,764 BOEPD. The company also indicated that—in the process of shifting its oil gathering from truck-based transport to pipeline transport—it had the majority of its Mustang and Appaloosa oil production being gathered via pipeline by the end of July.

Rick Betz, CEO of Resolute, said in the company’s Q2 earnings call that he expects that Resolute, “will shift predominantly to three well pads while studying the possibility of moving to four well pads,” with the intent of minimizing the instances of completing new wells next to older, depleted wells. He said that other operators have “used terms such as drilling the cube or mowing the grass,” to describe similar activities.

Black Stone Minerals

Black Stone Minerals (ticker: BSM) averaged 37.3 MBOEPD, which was a 5% increase over the average production from its previous quarter. The company’s production was made up of 76% natural gas. Approximately 57% of the company’s production is attributable to mineral and royalty interests.  The company reported an income of $54.2 million.

During its second quarter, the company focused its acquisitions on the Haynesville/Bossier play in East Texas, where it invested $18.1 million in cash and $45.7 million in equity. Through the first half of the year, the company invested more than $125 million in acquisitions.

As of the first half of 2017, BSM had participated in a non-operating working interest owner in its mineral acreage, where it spent $10.4 million in the second quarter. The company anticipates that it will invest a total of between $40 million and $50 million in its working interest participation program in 2017. The majority of that program is focused in the Haynesville shale and Shelby Trough in east Texas.

The expected investment was revised downward from an initial guidance range of $50 to $60 million.

Carrizo Oil & Gas

Carrizo Oil & Gas (ticker: CRZO) announced net income of $56.3 million for its second quarter of 2017—an enormous rebound from a net loss of $262.1 million in Q2, 2016. Carrizo averaged 51,019 BOEPD of production during Q2. The company’s Q2 production was an increase of 23% over its Q2 production in 2016. It attributed the growth in production to its Eagle Ford shale and Delaware basin developments.

The company also attributed some of the production growth to additional production out of its late-2016 Sanchez acquisition and an increase in production out of its Marcellus acreage. President and CEO Chip Johnson mentioned in the Q2 earnings call that Carrizo has “plans to divest [its] non-Texas assets,” in order to focus on its core Texas acreage.

Carrizo’s drilling and completions capital expenditures for Q2, 2017 totaled $148.4 million—with over 85% of that value attributed to the company’s Eagle Ford shale. The remainder of the company’s CapEx was weighted more towards the company’s Delaware basin and Niobrara assets. The company also had $34.4 million in expenditures in land and seismic expenditures in the Permian and Eagle Ford.

The company drilled 23 gross (21.2 net) wells and completed 26 gross (21.6 net) wells during Q2 in the Eagle Ford. Moving into Q3, Carrizo had 28 gross (26.6 net) wells in progress or waiting on completion in the Eagle Ford. The company planned to move one of its three operational rigs from the Eagle Ford to the Delaware basin, where it anticipates that it will drill 93 gross (80 net) and complete 93 gross (84 net) wells during 2017.

Carrizo intends to close the acquisition of properties in the Delaware basin from ExL Petroleum Management by mid-August. The acquisition is for approximately 16,500 net acres. The company has updated its drilling and completion plan in the new Delaware acreage and, as a reflection of that, has revised its 2017 drilling and completion guidance down to between $590 and $610 million.

The same changes have caused Carrizo to decrease its 2017 production guidance down to between 34,600 and 34,800 BPD from an initial guidance of between 35,700 and 36,000 BPD.

Denbury Resources

Denbury Resources (ticker: DNR) announced in its Q2 earnings update net income of $14 million. The company reduced its capital allocation from $300 million to $250 million—while still projecting to meet the midpoint of its 2017 production guidance.

The company averaged 59,774 BOEPD in Q2—97% of which was oil. The company’s tertiary properties accounted for 61% of its overall production. In conducting its tertiary recovery operations, Denbury used approximately 608 Mmcf per day of CO2 during Q2, 2017—an increase of 33% from Q2, 2016. The CO2 use grew approximately 6% from Q1, 2017—spurred by CO2 demand for the Hastings redevelopment.

During the quarter, the company initiated its Hastings redevelopment project and closed its Salt Creek acquisition. After the Salt Creek acquisition, Denbury has raised its 2017 production guidance to between 60,000 and 62,000 BOEPD.

Moving into the second half of 2017, Denbury anticipated the completion of phase 5 of its Bell Creek development, and the expansion of its recycling facility at Oyster Bayou.

Lonestar Resources, Resolute Energy, Black Stone Minerals, Carrizo Oil & Gas, and Denbury Resources are presenting at EnerCom’s The Oil & Gas Conference® 22

LONE, REN, BSM, CRZO, and DNR will be presenting companies at the upcoming EnerCom conference in Denver, Colorado—The Oil & Gas Conference® 22.

The conference is EnerCom’s 22nd Denver-based oil and gas focused investor conference, bringing together publicly traded E&Ps and oilfield service and technology companies with institutional investors.  The conference will be at the Denver Downtown Westin Hotel, August 13-17, 2017. To register for The Oil & Gas Conference® 22 please visit the conference website.

5 EnerCom Presenters Report Q2

August 4, 2017

Three companies that will be presenting at EnerCom’s 22nd The Oil & Gas Conference® have reported financial and operational updates for the second quarter of 2017.

Gastar Exploration

Gastar Exploration (ticker: GST) indicated today that it averaged 6,100 BOEPD in production—a number that exceeded its guidance for the quarter. Liquids made up 73% of total production.

The company’s president and CEO, Russell Porter, said that Gastar continues “to make progress delineating the Meramec and Osage formations,” and that the company had drilled a total of, “21 Meramec and 13 Osage wells across [its] STACK play,”—granting the company a bounty of information on its acreage.

The company holds 89,900 net acres, 63,200 acres of which is core STACK acreage. The remaining 26,700 acres is in the WEHLU trend.

EnerCom’s Presenting Companies Gastar, Goodrich, and Gran Tierra Report for Q2

Source: Gastar

Gastar is increasing its 2017 drilling capital budget to approximately $129.2 million in order to accommodate higher working interests, more operated wells, and an increase in non-operated drilling activity. The capital budget was increased by approximately $45.3 million.

Goodrich Petroleum

Houston based Goodrich Petroleum (ticker: GDP) announced that it had produced a total of 3.3 Bcfe for the quarter, averaging approximately 36,300 Mcfe per day—85% of which was natural gas. Goodrich’s Q2 production was 40% higher than its reported Q1 production, which averaged approximately 26,000 Mcfe per day.

The company’s production continues increasing, with an average July production of approximately 44,000 Mcfe per day. Goodrich as revised its production guidance to between 55,000 and 60,000 Mcfe per day. Goodrich also reported quarterly revenue of $12.5 million.

EnerCom’s Presenting Companies Gastar, Goodrich, and Gran Tierra Report for Q2

Source: Goodrich Petroleum

In its Haynesville Shale, Goodrich—as of its Q2, 2017 update—was in the process of drilling one well with a 10,000 foot lateral. After that well is completed, Goodrich intends to drill and complete another two wells—both with an expected lateral length of 7,500 feet.

Goodrich anticipates that its Haynesville acreage, which totals 50,000 gross (26,000 net) acres across Louisiana and Texas, has 250 gross (100 net) potential drilling locations.

The company added 3,000 net acres in two acquisitions during Q2.

Gran Tierra Energy

Gran Tierra Energy (ticker: GTE) indicated that it was producing 34,178 BOEPD as of the last week of July, 2017—an increase of 20% over its average Q1 production.

Gran Tierra announced progress in multiple development areas. In its Costayaco acreage, where it is targeting the A-Limestone, two horizontal wells are now on production.

EnerCom’s Presenting Companies Gastar, Goodrich, and Gran Tierra Report for Q2

Source: Gran Tierra Energy

A multi-zone discovery in an exploration well in its Putomayo basin showed production of 1,938 BOPD out of one zone and 217 BOPD from another zone.

Gran Tierra also saw good performance from two Putomayo wells that are targeting the N Sand, which produced over 2,000 BOPD between the two. The company has also more than doubled the production out of its Acordionero assets since acquiring the assets 11 months ago. The production has leapt from 5,620 BOPD to 11,958 BOPD in the field.

In an effort to focus more heavily on its Colombia assets, Gran Tierra sold its assets in Brazil for $38 million in late June. This caused the company to revise its average 2017 production guidance to between 33,300 and 34,300 BOEPD.

Gastar Exploration, Goodrich Petroleum, and Gran Tierra Energy are presenting at EnerCom’s The Oil & Gas Conference® 22

GST, GDP, and GTE will be presenting companies at the upcoming EnerCom conference in Denver, Colorado—The Oil & Gas Conference® 22.

The conference is EnerCom’s 22nd Denver-based oil and gas focused investor conference, bringing together publicly traded E&Ps and oilfield service and technology companies with institutional investors.  The conference will be at the Denver Downtown Westin Hotel, August 13-17, 2017. To register for The Oil & Gas Conference® 22 please visit the conference website.

EnerCom’s Presenting Companies Gastar, Goodrich, and Gran Tierra Report for Q2

Apache Corp. (ticker: APA) announced its second quarter results and operational updates August 3rd, and reported an average production of 388,000 BOEPD. The company earned $572 million during Q2.

Apache’s North American production totaled 244,000 BOEPD—where it averaged 18 rigs, and completed 36 gross wells. The Permian assets produced 146,000 BOEPD. In the Delaware Alpine High location, Apache continued testing and mapping.

In the North Sea, Apache averaged 55,000 BOEPD of production and ran an average of four rigs during the quarter. The company’s Egypt production was 89,000 BOEPD, where it ran an average of 13 rigs during the course of the quarter.

Earlier in the second quarter, Apache agreed to the sale of its Montney and Duverney acreage in Canada for just over $700 million. The company expects to close on the sale later in August, 2017 and believes that the divestiture allows it to focus more heavily on its Permian assets.

Without giving numbers, John Christmann—president and CEO—noted that “average cash margins per BOE, earnings per share, and free cash flow will be positively impacted,” by the Canadian asset sale.

Apache’s Q2 capital investment totaled $738 million—two thirds of which was geared towards the Permian assets. The company’s amount of cash on hand grew to approximately $1.7 billion from $1.5 billion in the first quarters. It also reduced its debt by $144 million, down to $6.8 billion.

Building up in Alpine High

Alpine High—Apache’s up-and-coming asset in the Permian—was allocated $128 million of the capital expenditures. There, Apache had six rigs operating, as of the Q2 update. Following the end of Q2, the company had 11 wells, total connected to its midstream facilities.

Apache had 35 miles worth of 30-inch trunkline for gas takeaway, as well as 40 miles of smaller gathering lines, and two gas processing facilities with eight central tank batteries in the Alpine High area. The company intends to bring another gas processing facility online in August, followed by two more in September.

Apache highlighted one well producing out of the Wolfcamp that had a 30-day average initial production of over 1,000 BOEPD.

Outlook

Following the divestiture of its Canadian assets, Apache revised its 2017 production guidance to between 354,000 BOEPD and 370,000 BOEPD for Q3, 2017 and to between 379,000 BOEPD and 401,000 BOEPD for Q4, 2017.

The company has not altered its 2017 capital budget guidance of $3.1 billion because the capital that was meant to be spent in the Canadian assets is going to be spent by the time the transaction has closed.

Apache Q2, 2017 Earnings Call Q&A

Q: Can you talk about how you expect the Alpine High to produce in the northern part of the field versus the south?

John Chrismann, president and CEO: I think the good news is, is we got online early. We were scheduled to bring everything on July 1. We have some of the stuff to talk about in the second quarter, because we were able to bring things on in early May. Things are progressing really as planned. We were able to sell net to Apache 7,400 BOEs a day in the month of June.

And like I said, we’ve been bringing up the CPFs. If you look at kind of where we are today on the infrastructure, we now have 35 miles of the 30-inch trunkline in. We’ve got over 40 miles of gathering in. There are two CPFs that are operating with eight tank batteries. And then in August and September, we’ve got our third CPF coming in – coming on in August, fourth and fifth in September, as well as a connection to the south.

And so what we’ve said is, our volumes are – we’re currently producing about 60 million a day net to Apache. You’re going to see that grow to 100 by September. And you’re going to see the liquids ratio grow as well, especially as we start to bring on more NGLs. So a lot of exciting things. We only had 11 wells on in the quarter, and really five of those have been constrained. So we’re really, really just getting started.

Q: Do you have a definitive timeline as far as when we’ll get more clarity around the potential resource at Alpine High?

John Christmann: We’re ramping up most of our wells, like the wells we disclosed on the last earnings call. We cleaned them up and shut them in. Most wells have been waiting. We’ve got – as Tim said in his notes, we’ve got a lot of wells waiting on the infrastructure. Now that we have the facilities and things, it doesn’t make a lot of sense to be flaring volumes and things. And so, as we bring more things on, I think you’re going to continue to see a lot of data coming. And when we get to a point that it makes sense to talk more definitively, what we really want to do is get the processing facilities lined out, get more time behind the wells, continue with our optimization work, and at some point, we’ll come back with something very meaningful and very definitive.

But I think what we’ve continued to state is that we feel very, very good that we have more than 3,000 wet gas locations. Your best EURs would be to look at what we disclosed at Barclays almost a year ago. And now we said with the two Wolfcamp wells that are, by the way, in two different zones in the Wolfcamp, in a significant distance between those wells, we feel very confident now that we have hundreds of locations in the Wolfcamp, so – that will be oil locations. And – so we’ll come back as we get more data. We’re really just getting started with our infrastructure and being able to bring things on and produce them into ideal production situations.

August 3, 2017

Approach Resources

Approach Resources (ticker: AREX) exceeded its production guidance for Q2, with production at 11.9 MBOEPD, and dropped its lease operating cost below guidance as well, at $3.92 per BOE.

Approach drilled a total of eight wells and completed another five. One of the completed wells was in the Wolfcamp A bench, two more in the Wolfcamp B bench, and the last two in the Wolfcamp C bench. As of the end of June, the company had ten horizontal wells waiting to be completed and one well being drilled.

Approach has also been able to “hold [its] drilling completion cost for a typical Wolfcamp well to around $4 million,” according to chairman and CEO Ross Craft in Approach’s earnings call.

Approach had $24.2 million in capital expenditures during Q2, $23.8 million of which was dedicated to drilling and completion activities. Approximately $1.5 million was allocated to infrastructure costs and equipment—with $0.9 million offset by sales tax refunds.

Approach intends to complete between two and four wells during its third quarter and has projected its production to be between 11.8 and 12.0 MBOEPD.

Eclipse Resources

Eclipse Resources (ticker: ECR) achieved average production of 287.8 MMcfe per day—above its 265 and 275 MMcfe per day production guidance. The company’s Q2 net income totaled $11.5 million, as compared to a loss of $73.2 million in the second quarter of last year.

Eclipse’s revenue was $86.2 million, significantly ahead of Q2, 2016, which was $47.1 million.

Eclipse also committed to a joint drilling venture with Sequel Energy Group to drill in Eclipse’s Utica shale acreage in southeast Ohio. The venture will include funding from Sequel up to $325 million for two drilling programs. The programs—which are expected to end in 2018—include plans to drill 34 gross wells. Eclipse will be the operator of the wells.

As of the Q2 report, Eclipse was completing two of its “super-lateral” wells—what Eclipse’s chairman, president and CEO, Ben Hulburt, “believe[s] to be the longest onshore lateral wells ever drilled.” Two super-laterals undergoing completion are the Great Scott 3H, with a 19,100 foot lateral, and the Outlaw C11H, with a 19,500 foot lateral.

Unit Corporation

Unit Corporation (ticker: UNT) reported $9.1 million in net income, up from a loss of $72.1 million in Q2, 2016. The company had total revenue of $170.6 million for Q2, 2017. Of that revenue, 49% was sourced from the corporation’s oil and gas segment, 23% from its contract drilling segment, and 29% from its midstream segment.

The company produced a cumulative of 3.9 MMBOE during Q2, 2017—approximately 7,851 BOPD of oil, 12,456 BPD of NGLs, and 131,940 Mcf per day of natural gas. In its Wilcox area, the company tested an exploration well in the Cherry Creek prospect. Unit intends to build horizontal well inventory in its Wilcox area.

Unit is also continuing its Buffalo Wallow extended reach lateral drilling program, which should extend through the remainder of 2017.It brought two wells to first production in the area during the quarter.

The company’s Southern Oklahoma Hoxbar Oil Trend assets—acquired in Q1—are being evaluated for the incorporation of longer lateral wells. Unit believes that it will initiate a drilling program in its STACK acreage by late 2017 or early 2018.

The company’s contract drilling segment experienced an average of 28.8 working rigs during Q2, 13% higher than the first quarter. At the end of the quarter, the company had 33 rigs being utilized.

Approach Resources, Eclipse Resources, and Unit Corp. are presenting at EnerCom’s The Oil & Gas Conference® 22

AREX, ECR, and UNT will be presenting companies at the upcoming EnerCom conference in Denver, Colorado—The Oil & Gas Conference® 22.

The conference is EnerCom’s 22nd Denver-based oil and gas focused investor conference, bringing together publicly traded E&Ps and oilfield service and technology companies with institutional investors.  The conference will be at the Denver Downtown Westin Hotel, August 13-17, 2017. To register for The Oil & Gas Conference® 22 please visit the conference website.

Approach, Eclipse, Unit Corp. Report Q2

In its second quarter, PetroQuest Energy (ticker: PQ) produced a total of 6.3 Bcfe up from 6.0 Bcfe produced in Q2, 2016. PetroQuest had a loss of $3,385,000 for Q2, 2017, down significantly from a Q2, 2016 loss of $24,143,000. The company’s production for the first half of the year was 11.5 Bcfe. The company reported lease operating costs of $1.12 per Mcfe, a decrease of $0.02 since Q2 2016.

The company’s average daily production was 69.5 Mmcfe per day during Q2. The company is waiting to restore production from its recompleted Ship Shoal 72 well, which it believes will add another 6 Mmcfe per day of net production. PetroQuest has set a guidance of between 85 and 90 Mmcfe per day.

PetroQuest has—as of the end of Q2—begun completions operations on a two well pad in which it holds an average of 76% working interest in its northern Cotton Valley acreage. It is utilizing a completions strategy that is similar to the strategy that yielded record production of 18.3 Mmcfe per day out of its PQ#25 well.

PetroQuest is also almost finished with drilling operations in its PQ#28, and expects to begin completions operations in four to five weeks.

The company reinitiated its Cotton Valley drilling program in late 2016. In the time since, PetroQuest has experienced a growth of 50% in its revenues, and a doubling of its cash flow, as well as a 38% increase in production.  PetroQuest’s first multi-well pad in the Cotton Valley started with strong production, reaching a total initial production rate of approximately 38 Mmcfe per day.

PetroQuest Energy is presenting at EnerCom’s The Oil & Gas Conference® 22

PetroQuest will be a presenting company at the upcoming EnerCom conference in Denver, Colorado—The Oil & Gas Conference® 22.

The conference is EnerCom’s 22nd Denver-based oil and gas focused investor conference, bringing together publicly traded E&Ps and oilfield service and technology companies with institutional investors.  The conference will be at the Denver Downtown Westin Hotel, August 13-17, 2017. To register for The Oil & Gas Conference® 22 please visit the conference website.

 

PetroQuest Energy Reports for the Second Quarter, 2017

August 2, 2017

During Q2, Devon Energy (ticker: DVN) averaged approximately 536,000 BOEPD which was 6,000 BOEPD higher than the company’s midpoint guidance for the quarter. Of that, approximately 44% of the production was oil.

Devon indicated that 412,000 BOEPD of its total 536,000 BOEPD was sourced from U.S. resource plays.

The company believes that its liquid volumes will reach approximately 65% of its product mix. Currently the company is forecasting crude oil production of between 234,000 and 244,000 BOPD for the third quarter.

The company also has revised its 2017 capital outlook to between $1.9 and $2.2 billion—roughly $100 million less than its last guidance. The revision has taken place without any alterations to its planned activity levels. Devon intends to reach 20 operating rigs by the end of 2017—the majority of which will be concentrated in the Delaware or STACK—where Devon has over 30,000 potential drilling locations.

In its operations, Devon highlighted a few top producing wells in its STACK and Delaware assets—of which nine wells achieved 30-day initial production rates averaging around 2,000 BOEPD. One well, the Privott 17-H in the STACK, reached a peak of 6,000 BOEPD.

The company also announced that its divestitures totaled approximately $340 million. One such, announced in July, was a divestiture of Eagle Ford acreage to Penn Virginia.


Legal Notice