Abraxas Petroleum Corporation

Geoffrey R. King - Chief Financial Officer and Vice President Robert L.

G. Watson - Chairman, Chief Executive Officer and President

Will Green - Stephens Inc., Research Division Stephen F. Berman - Canaccord Genuity, Research Division Noel A.

Parks - Ladenburg Thalmann & Co. Inc., Research Division

Thank you, Steve, and good morning, everybody. Welcome to the Abraxas Petroleum First Quarter 2015 Earnings Conference Call.

Bob Watson, President and CEO of Abraxas, joins me today. In addition, we have our Chief Accounting Officer and our VPs of Operations and Exploration available to answer any questions that you may have after Bob's overview.

As a reminder, today's call is being taped and a webcast replay will be available immediately after the conclusion of the call. I'd like to remind everyone that any statements made during this call that are not statements of historical fact are considered forward-looking statements, and actual results could vary materially from those contained in these statements.

Factors that could cause our actual results to vary are described in our filings with the Securities and Exchange Commission. I would encourage everyone to review the risk factors contained in these filings and in our press releases.

I'll now turn the call over to Bob.

Thank you, Geoff. Good morning.

The first thing I'd like to do is explain the small production shortfall from our first quarter. Up in the Bakken, we've made it a point since day 1 to make sure that we had that gas takeaway capacity on all of our pads before we brought wells onto production.

In January, we are serviced by ONEOK, their gathering system, into their Bear Den plant. The plant had an issue.

Their sales line hydrated off, it basically froze off, and we went to 100% flare. We didn't have any idea how long it would last, so we didn't do any production curtailment at that time other than not being able to sell gas.

The North Dakota Industrial Commission, NDIC, as most of you know has a new flare -- has new flare rules that went into effect last fall. And the current maximum amount of gas that you can flare company-wide is 24%.

We got a letter in March that we had exceeded our flare limits, which we knew, and the letter required us to curtail production in the ascending wells to no more than 100 barrels a day starting April 1, which we also knew. We petitioned the NDIC for relief to -- due to force majeure because there is a provision in the rules for relief in such instances, and they took it under consideration.

In the meantime, they took it on themselves to issue a press release saying Abraxas was 1 of 6 or 7 flaring offenders, mostly small companies. And we still don't know why the big companies escaped the list because they were subject to the same gas plant issues.

And the NDIC said, "Well, we need proof that you had gas takeaway capacity when the wells were completed." And which we see their point; they don't want people drilling wells, knowing they don't have capacity and waiting for capacity to arrive and then petitioning the NDIC for relief because they don't have capacity.

But we showed, and we got a lot of cooperation from ONEOK, who was certainly helpful in the process, but we showed that we were selling essentially 100% of our gas before the freeze-up. You will always have a little bit of flare coming from low-pressure instrumentation gas, which just can't be recovered.

But we were essentially producing -- or selling 100% of our gas, which proved we had capacity, and we're now back to selling 100% now. So we finally got a relief letter early in April after curtailing some production, not much, but still we had to curtail some.

But Q1 was impacted by no gas sales in the Bakken for about half a quarter. In addition to that, the Regency gas plant that we use out in West Texas and the Delaware Basin also went down for maintenance for about 6 weeks during the latter part of the quarter and into the second quarter.

So the net impact from both was about 6 million a day raw gas net to us for half a quarter, which results into about 500 BOEs per day averaged over the full quarter. Good news.

Both issues are now fixed. The Bakken issue was fixed in March and -- although we still had some periodic highline [ph] pressure issues.

And the West Texas Regency plant went back on this past weekend, so it will have some impact on the second quarter. But without these issues, we would have been well above our Q1 guidance.

Last year, we made the decision to not frac any wells, late last year, until costs came down at least 35%. We ended up with 9 drilled and noncompleted wells in inventory: 2 in the Eagle Ford, 4 in the Bakken and 3 in the Permian.

Costs have now come down in excess of 35%, so we've made the election to go ahead and frac all 9 wells here during the second quarter. That process is underway in the Eagle Ford.

Our Grass Farm 2H was successfully fracked with a 30-stage frac that was completed this past weekend and the well is now on flowback. And we -- in the Eagle Ford, we expected about a 38% reduction in frac costs, and then in the Grass Farm well, we did at least that or perhaps a little bit better.

We're currently fracking the -- our Henry 1H with a 34-stage frac. It's underway.

Both of these wells we own 100% of and both of these wells involve a new frac design for us, essentially more but shorter stages and more frac sand per foot of lateral. We've increased from 1,500 pounds to about 2,000 pounds.

Up in the Bakken, we've got 4 33-stage fracs scheduled to commence about May 20 on our ore well Jore West pad, where we own about a 76% working interest. And we expect frac savings of about 50% from these wells.

Out in West Texas, we have 3 Clearfork wells scheduled to be fracked within the next 2 weeks, and we have about a 90% working interest in those 2 wells. Now sometimes in our business we really can't accommodate the Wall Street infatuation with quarter-to-quarter results.

Sometimes we just have to do things that negatively impact one quarter to benefit future quarters. Last week, along with the fracs, we announced that, out of an abundance of caution, we were shutting in about 10 wells near these active fracs, and they'll be shut in for about 4 to 6 weeks to help minimize issues that can occur with frac hits.

We could have been a little bit more aggressive and not shut in as many wells, but we decided that, for the long-term best interest of the company, it was best to shut in these 10 wells. The bottom line is about 1/3 of our production will be shut in for about half the quarter.

The good news is these wells should come back on sometime in June, along with 9 new wells. So the third quarter and fourth quarter look very strong for us and we should more than make up for the lost time.

But simple math, one low quarter along with 3 good quarters, the average for the year is a little bit lower. Thus, we lowered our guidance to 6,500 to 7,000 barrels a day average for the year, which is the midpoint is still an 18% growth over 2014 average.

In North Dakota, our company-owned rig continues to impress, so much so that we will now drill more wells in 2015 than originally planned. We're just drilling them quicker, which is good.

And due to service cost savings, we can still accommodate these additional wells and only increase our capital expenditure budget from $54 million to $55 million, which should still generate free cash flow. Specifically, the rig is on a 3-well Ravin Northwest pad in McKenzie County.

The Stenehjem 5H should reach TD today at about 21,000 feet, a liner will be run, the rig will walk to the Sten-Rav 1H to drill its lateral. Intermediate casing has already been set at about 11,000 feet.

And then on to the lateral for the Ravin 8H. The timing of the completion of these wells will depend on service costs, oil prices and adequate gas capture.

We need to make sure, because of the new NDIC rules, that we can sell 100% of our gas. The rig will then move to an 11-well Stenehjem pad to drill the first 6 of the 11 wells, and then probably move to an additional pad after that, hopefully by the end of the year.

We recently completed the third bolt-on transaction on a drilling spacing unit that directly offsets one of our existing drilling spacing units. That third transaction, which we announced last week, now gives us a greater than 50% working interest in that DSU.

We plan to take over operations and plan to drill 15 wells at Middle Bakken and Three Forks with our company-owned rig, which means cheaper wells and better economics and for an additional 1.5 year of inventory out in front of the rig. Currently we have on book additional reserves associated with this interest of about 4.5 million barrels of equivalent.

So it is a very significant transaction, even though on the surface it looks like it's a very minor deal. We're continuing to negotiate on additional bolt-ons with similar economic impacts.

And we continue to source larger deals. But so far we found that the bid ask is a bit wide.

The current strength this week in oil prices has probably not helped this issue. But we continue to look and to evaluate.

But rest assured, if we do a bigger deal, it will not be a nonaccretive transaction or one that stresses our balance sheet. And after that, we'll ask for questions.

Steve, we're ready for questions.

You obviously just mentioned the acquisition you guys recently did in the Bakken. Are you still seeing better opportunities in the Bakken?

Are you still looking in the Eagle Ford? Are we more likely to see you guys do something in the Bakken?

How should we think about the potential acquisition front?

I would say it's 50/50 at this point. It just so happens that with the bifurcated interest in the Bakken, where you can pick off small interests from a number of parties and they add up to a bigger interest, those types of deals are probably a little bit easier than doing deals in the Bakken -- in the Eagle Ford, where you're dealing essentially with 100% owner of those leases.

So you'll probably hear a little bit more noise coming from the Bakken. But as far as impact on the company, it's still going to be about 50/50 Eagle Ford and Bakken.

Got you. And can you remind us of what the process is like of petitioning to get operatorship of that DSU and how long you expect that to take and when you should have permits at hand and all that sort of good stuff?

Well, unfortunately, this is a federal unit, so we're up to the BLM's timeframe on issuing permits. But we will be petitioning the NDIC in 2 months for downspacing and taking over operations.

It's pretty cut and dry at that point. If you own more than 50%, the precedence is that you will be granted operatorship.

It's possible, if we get permits in time, that after the 6 wells on the Stenehjem big pad that we could move down to this unit and commence drilling the first pad on that one. But getting federal permits is very difficult and timely these days, so there's no time budget yet that we have in our mind.

Got you. And then you mentioned the Jore Wells are scheduled to frac soon.

What's the best way to think about that offsetting production and how much it contributes? Just so we can think about that downtime that's associated with those offsetting wells.

Well, all I've done is added up all of them, both in the Eagle Ford and in the Bakken, and it comes out to about 1/3 of our production from anywhere from 4 weeks to 6 weeks being shut in while we frac and complete the offset wells.

Bob, you've talked recently about maybe doing some stuff up in the Powder River as well as the Permian. I know there's permitting -- federal permitting issues up in the Powder.

Can you -- any updates on either one of those?

Well, in the Powder, we've elected to go ahead and get permits on our state lease, which is the lease where the Hedgehog well is located. So we're currently thinking if we can't get federal permits on a timely basis, which we probably can't, and we also have found out that we have a coal mine issue there we have to deal with, and so that might be the pacing item, is when the coal mine allows us to get onto the surface to drill those other leases.

But in the meantime, it's entirely possible we might go ahead and drill 2 wells on that state lease, offsetting the Hedgehog. And that could be done late, late summer, early fall time frame.

We would not be using our rig to do that because we feel like we need 5 wells minimum to move our rig down there. But there's ample rigs available up there to drill, and we feel like it's still a very commercial venture for us.

And in the Permian?

We're -- we've got the 3 fracs scheduled for week after next. And depending on the results there, that could kick off a redevelopment program for us there or we might want to sit back and watch production for a while.

A lot is going to depend on the success of those fracs and what kind of production increase they show.

Got it. And one for you, Geoff.

Can you talk about this hedge monetization? When was that done?

And just to clarify, that was all your remaining 15 hedges and then you put some new ones on?

Yes, it's 2 things. We've actually had some things that need to be corrected as far as that goes.

It was done earlier this week. What we monetized was just our oil hedges in 2015.

That allowed us to capture that value and then now we're protected even more on the downside in case that comes about in '15, as well as we can participate more the upside than we could originally by just keeping those swaps on. The other thing that was put out there is somebody was calling them knockout swaps.

They're not knockout swaps. They just have sub-floors on them so -- on the 2016 hedges.

I wanted to get some more thoughts from you on the service environment. We've had this bit of an uptick in oil and even heard some of the larger operators talking about maybe adding back rigs in a few areas like the Permian.

From -- when prices went below $70, say November time frame to now, can you just give me a sense of what the back-and-forth has been like with your service vendors? Clearly they didn't give up the cost concessions right away.

I'm just trying to get a sense of whether you think we've seen as much give-back from them as we're going to see for the time being?

It was a gradual process. Prices kept coming down.

We kept holding fast and we told them what we needed. When it looked like overall prices were down to the range we were looking for, we went out for bids and we got a large response on numbers of companies that wanted to bid on it.

So we take from that, that there's still plenty of competition out there for the available work. I personally feel like we're probably seeing the bottom of that because, with this little uptick in oil price, I think you're going to see people accelerate the completion of the drilled and uncompleted wells, and that's going to tie up some of the capacity.

I think what's happened with the pumping service companies anyway is they've parked a bunch of equipment and plan on keeping it parked until the equipment that they have still running is fully utilized. And I think the completion of the drilled and uncompleted wells, we'll probably fully utilize that by summertime.

And I think they're going to be a little bit hesitant to put that rest of that equipment to work until we have more of a long-term trend on activity levels. So we're very fortunate to get this done now because I think we're seeing the lowest prices that we would have seen had we waited later on in the summer.

Great. And as far as the service companies that have parked equipment, is that the small ones, mom and pops, as well as large?

Or just one or the other?

Well, when I drive south of town to my farm, I drive right past Baker Hughes, Halliburton and Weatherford. And you can see an awful lot of iron in their yards.

So I suspect that everybody is parking equipment.

Okay, got you. The other thing, thinking back in the Eagle Ford, it was interesting to hear you say that you've gone for I think it was shorter stages with more proppant, is your updated design, is that right?

That is correct. We've cut our stages down to about 140 feet from about 220 feet.

We've increased our -- our perforation clusters are still the same distance apart, but now there's only 3 clusters per stage instead of 5. The theory there is that when you have 5, you have a greater chance of some of them not taking the frac than if you have just 3.

And then on top of that, we've increased our proppant from 1,500 pounds a foot to around 2,000 pounds per foot, which seems like that's a trend that's going through the Eagle Ford and with some pretty good results. So we've got our fingers crossed and we'll see how these 2 wells come back on us.

Great. Great.

And thinking back to -- I think it was the Spanish Eyes and the Eagle Eyes were the couple wells that I think have been a little bit of a mystery as to why they didn't perform as well as some of their closer offset. At this point do you have a better sense of stability from well to well of what you might see going forward?

I wish I could say yes, but we probably don't. Now what we're -- what we've done on this Grass Farm well is we've -- and used -- we've run salt tracers, and there's 19 different chemical components that are available.

We did 30 stages, so we had to group a couple of them, 2 stages per salt. So now we'll be able to see which stage is contributing the most production on a periodic basis for probably the next 180 days or so.

We'll be sampling that oil and running it through the lab and they'll come back with a percentage -- what percentage of the production is coming from which stage. Hopefully that will tell us where the predominance of the production is coming from, because the Grass Farms is a direct offset to the Snake Eyes, which is our best well.

And if that corresponds to information that we're seeing with our seismic attribute work that we're doing right now, that might tell us that fracture swarms that we encounter are contributing the most production. I don't know, but the combination of those 2 items might give us some pretty revealing information.

We're certainly hopeful of such. And since we don't have any immediate term -- plans to drill additional wells in the Eagle Ford yet anyway, we can use this slow time to do all this technical background work.

Thanks, Steve. We appreciate your participation today in Abraxas's Earnings Conference Call.

As I mentioned at the start of the call, a webcast replay will be available on our website and a transcript will be posted in approximately 24 hours. Thank you, and have a great day.