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.
