Northern Oil and Gas Inc (NOG) 2014 Q1 法說會逐字稿

Good day and welcome to the Northern Oil and Gas Incorporated first-quarter 2014 earnings conference call. Today's call is being recorded.

At this time I would like to turn the conference over to Michael Reger. Please go ahead, Sir.

Thank you, Joe. Good morning ladies and gentlemen, this is Mike.

We're happy to welcome you to our 2014 first-quarter earnings call for Northern Oil and Gas. With me today is Tom Stoelk, our Chief Financial Officer, who will discuss our financial highlights from the quarter.

Before we begin this morning's call, you should be aware that certain statements made during this call may contain forward-looking statements that are based upon management's expectations, estimates, projections and assumptions and that involve certain risks and uncertainties. We encourage you to review the various risk factors relating to our business which are available in our annual report on form 10-K for the year ended December 31, 2013, and other reports we have filed with the SEC.

These forward-looking statements relate to our future plans, objectives, expectations and intentions. Our actual results could differ materially from those contemplated by these statements, partially as a result of the various assumptions relied upon in making such statements. During this conference call, we will also make references to certain non-GAAP financial measures, including adjusted net income and adjusted EBITDA. Reconciliations of these non-GAAP financial measures to the applicable GAAP measures can be found in the earnings release that were issued last night.

I'll start us off here with an operational update and discuss our outlook for the remainder of the year, and then I'll turn the call over to Tom to cover our financial results. Weather-related issues clearly affected the first quarter of 2014 with severe cold temperatures significantly impacting completion activities. That had a negative effect on overall operations and production as well. This probably isn't news to anyone.

During the first quarter, we added just 89 gross wells 4.6 net wells to production, bringing our total producing well count to 1847 gross or 150.8 net wells. The good news is the completion activity picked up materially in April, and as a result, we have had more net well completions in April than the entire first quarter.

We added 80 gross 6.7 net wells in April alone, so we are encouraged to see the delayed completions in the first quarter shift to heavier completion activity right out of the gate in the second quarter.

On another positive note, despite the brutal weather in the first quarter, our drilling activity continued at an above average pace with 13.8 net wells being spud during the first quarter. That brought our total number of wells in process as of March 31 to 298 gross wells and 24.4 net wells which, is a record high for Northern and a considerable increase from the 15 net wells we had in process at the end of December.

What's really encouraging about our inventory of in process wells is that 94% of this activity is occurring in Mountrail County, McKenzie County Williams and Dunn counties, compared to 2013 when these counties accounted for approximately 75% of our net wells added to production during the year. Historically, these four counties have produced our highest overall returns with our drilling activity more concentrated in our core areas, along with pad drilling efficiencies and enhanced completion methodologies we are confident our production and overall returns will push higher.

All of this should position us really well for the remainder of 2014. I will say though, it is only May 9 so it is probably not prudent for us to make any changes in our annual production guidance at this time. We clearly see activity levels that are very strong and completion activity that picked up in April.

Also, with road weight restrictions expected to be lifted by the end of May, we are clearly optimistic the second quarter -- about the second quarter in 2014 as a whole. But again it is still early.

We are obviously expecting an increase in production in the second quarter and the back half of the year but we would like to see some follow-up to the strong completion activity in May, see the actual -- see the road restrictions actually come off in May and have a better grasp on the expected increase in production before adjusting our guidance.

One quick note on well costs, we are seeing a number of operators employing fracturing techniques requiring larger amounts of slick water and proppant, which has been offsetting some of the cost efficiencies gained from pad drilling. It is still early, but the preliminary results of the new completion enhancements have been positive, and we will continue to monitor the effect it has on returns. With that said, we are currently maintaining our estimate of $8.8 million per completed well for the year.

Wrapping things up, before I turn the call over to Tom, we are definitely seeing some really positive signs as we look at the remainder of 2014. Our backlog of 24.4 net wells in process as of March 31 is literally twice as large as it was on that date last year. And 94% of these wells are in our four best performing and highest return counties.

In addition, based on what we saw in April, expected -- we expect that we will work through the backlog earlier this year than we did last year when the big completion push didn't occur until the third and fourth quarters of last year. Again giving us confidence that our production and overall returns will push higher in 2014.

With that said, I'm going to turn the call over to Tom Stoelk, our Chief Financial Officer, to discuss the financial highlights for the first quarter of 2014.

Thanks, Mike.

For the first quarter we reported GAAP net income of $6.6 million or $0.11 per diluted share. Our adjusted net income, which excludes the net of tax impact of a non-cash loss on the mark-to-market of derivative instruments, was $11.4 million or $0.19 per diluted share. Our adjusted EBITDA for the first quarter total was $65.1 million.

During the first quarter, our total production volumes were proximally 1.2 million Boe or an average of 13,287 Boe per day, which was up 20% compared to the same period last year. On a sequential quarterly basis, average production volumes declined 5%, due to lower well completions and weather impacted operations.

As we previously mentioned, we remain positive on the industry activity and production volumes for the balance of 2014. Subject to seasonal road restrictions and any lingering road effects, we believe the majority of the completion activity that was delayed in the first quarter has shifted to the second and third quarters of 2014.

Oil and natural gas sales reached $96.8 million during the first quarter of 2014, which was a 16% increase as compared to the same period a year ago. Our average oil price differential to the NYMEX WTI benchmark was $13.42 per barrel in the first quarter of 2014, compared to $3.62 per barrel in the first quarter of 2013 and $14.98 per barrel last quarter.

At the beginning of the first quarter of 2014, the Company's price differential and NYMEX WTI increased due to pipeline market continuing to weaken, as well as refinery downtime and increased production from both the United States and Canada. A higher average NYMEX oil pricing in the first quarter of 2014, as compared to the first quarter of 2013, was more than offset by this nearly $10 increase in oil price differential in 2014. More recently oil differentials appear to be trending lower.

Our realized price per barrel of equivalent -- on an equivalent basis, after reflecting our settled derivative transactions, was $75.25 in the first quarter of 2014, which was 1% higher than last quarter, but was 9% lower when compared to the first quarter of last year.

As a result of oil price derivative activities, Northern incurred a cash settlement loss of $6.8 million in the first quarter of 2014, compared to loss of $371,000 in the first quarter of 2013. As a result of forward oil price changes, our non-cash mark-to-market derivative gains and losses resulted in a non-cash loss of $7.9 million in the first quarter of 2014, compared to a non-cash loss of $14.9 million in the first quarter of 2013.

Production expense was [$229,000] during the first quarter of 2014, as compared to last quarter and reached $11.7 million, although aggregate production expenses increased just slightly in the first quarter as compared to last quarter. Weather disruption and fewer well completions impacted operations and cost average production expense per Boe to climb.

On a per unit basis, the average projected expense per Boe increased from $8.85 per Boe in the fourth quarter of 2013 to $9.76 per Boe in the first quarter of 2014. The greater cost on a per unit basis in 2014 is primarily due to harsher weather conditions, as well as increased work-over-water hauling and disposal expenses.

Despite production expenses in the first quarter of 2014 being weather impacted, we still believe our full-year 2014 production expenses on a per unit basis will average approximately $9 per Boe, which we believe will trend lower throughout the year as weather improves and production levels ramp.

We pay production taxes based on the amount of oil and gas natural gas sales, production taxes total $9.8 million in the first quarter of 2014 or approximately 10.1% as a percentage of oil and gas sale. This compares to average production tax rates of 9.4% in the first quarter of 2013 and 9.7% in fourth quarter of 2013.

The Company's production tax rate increased in the first quarter of 2014, due to decreased trading of oil revenues on wells receiving tax incentives or the current the standard is it makes in our oil and gas pricing (inaudible) sales continue to trend higher throughout 2014. Likely averaging in the mid 10% range for the full year 2014.

Interest expense was $4 million for the first quarter of 2014, which was essentially flat compared to the first quarter of last year, as increased insurance costs were offset by lower compensation expenses. On a per unit basis, our general administrative expenses for Boe decreased 16% from $3.99 per Boe in the first quarter of 2013 to $3.34 per Boe in the first quarter of 2014.

Depreciation and amortization (inaudible) was $36.1 million in the first quarter of 2014 or $30.19 per Boe, which compares to $26.8 million in the first quarter of 2013 or $26.78 per Boe. Depletion expense, which is a largest component of our DD&A, averaged $30.02 per Boe in the first quarter of 2014, as compared to $26.66 in last year's comparable period. Depletion rate per Boe of $30.02 was determined based on year-end reserve report and will remain at that level until we update the reserves, likely not until the fourth quarter of this year.

Turning to liquidity, we recently completed our semiannual borrowing base redetermination where our borrowing base was increased to $500 million. At March 31, 2014, we had $138 million drawn on our revolving credit facility leaving us with $362 million of borrowing availability under the revolver. Including our senior notes, our total in debt at the end of the quarter was [$647.2] million and the ratio of our long-term debt the trailing fourth quarter's adjusted EBITDA was 2.4 times. We believe we have more than enough liquidity to handle our current backlog wells in process and we expect our cash flows to continue to grow and keep us in a strong financial position.

During the first quarter of 2014, our capital expenditures totaled $116.1 million, a breakout of that is as follows: Approximately $102.8 million drilling and completion capital includes capitalized workover expenses; $11.4 million on acreage and other acquisition activities in the Williston Basin; and $1.9 million of capitalized interest and other capitalized cost.

As previously mentioned, we believe the majority of the completion activity that was delayed in the first quarter will ship to the second and third quarters of 2014. Please note that the $102.8 million of drilling and completion capital includes accrual amounts attributable to our significant increase in wells in process that occurred during the first quarter.

During the first quarter of 2014, we repurchased approximate 1 million shares of Northern's common stock under our stock repurchase program at a total cost of approximately $13.7 million or $13.46 per share. That brings our total shares repurchased since October 2013 to 3.1 million shares or approximately 5% of our total outstanding shares at an average cost of $13.04 per share. We continue to layer in these opportunistically as the market warrants to increase the predictability of our cash flows and maintain a strong financial position.

For the remainder of 2014, we currently have hedged approximately 10,400 barrels of oil per day using swaps and an average price of $90.24, and approximately 650 barrels of oil per day using cost scholars with an average floor price of $90 an average ceiling price of $99.05 per barrel. In 2015 we have hedged approximately 8900 barrels of oil per day at an average floor price of $89.23. We will continue to evaluate and monitor further hedging opportunities as we progress through 2014.

At this time I'd like to turn the call back over to the operator for Q&A. Joe, if you could please give the instructions for Q&A.

(Operator Instructions)

Scott Hanold, RBC Capital.

Good morning.

Good morning, Scott.

It sounds like you all are pretty optimistic about the trend on where things are going, and obviously a little bit cautious given there's a lot of uncertainty. But could you give a little bit of color, if you have it, on maybe what a most recent month of production rate looks like if you have like March and April?

And also, as you look forward in terms of what's going to happen in Q2 and Q3, obviously things tend not to be linear. So taking the $6.7 million that you had in April and figuring that you are going to have a monster second quarter is probably not the right thing to do.

But can you kind of guide us to what you think that number could look like based on which operators are in that inventory?

Scott, this is Mike.

I think we'll wait until we have a better grasp on April's production and May and June before we talk about the second quarter. We averaged in the first quarter about $13.3 million a day.

As you can imagine, with more wells completed in April than in the entire first quarter, I guess we can imagine or expect that that production number increased pretty materially as we moved into the second quarter. I think we'll wait until we have more concrete data and get all of our production data in from our operating partners before we provide any guidance on that.

As you can imagine, given the current backlog and, more importantly, the quality of the backlog and the number of wells we completed right out of the gate in April at the beginning of the second quarter, we're expecting a strong second quarter.

Maybe a follow-up question here too then.

Obviously, as you stated, your backlog is much more weighted to the core of the play than it had been in 2013. Does the mix of the operators you're working with as well change a little bit there too? Can you give a little bit of color on that?

The mix doesn't really change a whole lot. It's our usual suspects: Slawson, Hess, Continental, EOG, et cetera. We have some great exposure in Dunn County to Conoco, so we're pretty encouraged with the mix.

And basically, it's just an increased shift back into the core for infield drilling. So as that continues to happen, we think we're going to stay in the 90%s in the big four counties. If you think about it, one of the stats that we provided in the commentary a few minutes ago was that 75% of the net wells we added in 2013 were in the big four counties of Mountrail, McKenzie, Williams and Dunn. And now that's in the 90%s; and our D&C list, our average is 94%.

Not as much activity in 2014 in Richland County. It's really just right in the core of North Dakota where we are seeing the activity.

We believe that's going to bode well for returns and be responsible for a material push in production here in the second quarter and the second half.

Thanks. And one final one.

Tom, can you give us a sense of, in terms of looking at share buybacks, what the restricted payments basket looks like. And what are your thoughts, just generally speaking, with the remainder -- I think its $110 million you've got on authorization to look to continue that program?

We're limited under the senior notes arrangement, Scott, with a basket. And that basket stands right now at about $67 million as of the end of the quarter. We'll just continue to monitor the stock price and things like that.

We certainly have the authorization to do it and have the capability to do it and also, more importantly, have the liquidity to be able to kind of do it. But it's kind of a wait and see. If an opportunity develops and we decide to take advantage of it, we will.

The short answer to your question is we have about $67 million under the restrictive payments basket that would be available to us.

I appreciate that. Thanks.

Thanks, Scott.

Peter Kissel, Howard Weil.

Thanks.

How are you? Thanks for taking my questions.

Mike, you just referenced it again. But I know with 94% of the current activity in the core counties, 75% last year, do you happen to have that number for 2012 just so we can get a sense for the progression of quality drilling?

We ran that number this morning, and it was about 61% in 2012. So you can see the progression back into the core. That was for 2012.

2013 it was about 75% in the big four counties. And then this year it's going to be, we think, in the mid-90%s.

We had a lot of activity in 2012 in Divide County. I think our current divide percentage is less than half of 1%. It's relatively immaterial.

You can see as we've focused more on the core and as we've started to, over the last 18 months or so, really focused on trying to high grade our capital expenditures, you can see the decisions we're making to participate in wells really lie in those big four counties.

Got you. Thanks.

I know in the past you've implemented an internal IRR our threshold when electing to participate in new wells.

Could you please just refresh us on what that IRR threshold is? And internally, does the Board look at moving that any time soon? And if they did, would it really impact that many locations anyway?

I think back when the drilling costs had come up and were peaking in late 2011 and then into 2012, we really had to take a really hard look at returns just because the Internal Rates of Return are affected so much by the actual drilling and completion costs upfront. That's when we started take a look at it.

Over the last year or so, we've ratcheted our Internal Rate of Return minimum threshold to the 20% range. And we really don't see a lot of well proposals that fall below 20%. Drilling costs have come down; and the well proposals we're seeing and the activity we're seeing and the AFE's we're getting are all coming from the core, mainly from infill drilling.

A couple of years ago, as you know, to be candid with you, we were getting a lot of well proposals. And operators were testing the edges of the play. We were acquiring a lot of acreage and units on the edge of the play. And I think our returns were affected negatively because of it back in 2011 and 2012.

Over the last 18 months, as we've really high-graded our capital expenditure, we're going to see our overall returns improve. We're going to see the productivity on a net-well basis improve.

And then I think that's going to lead us to the holy grail of cash flow positive here maybe sooner than we expected. Because it all just comes down to the quality of the wells we're bringing on and the cost to bring them on.

So we're really encouraged by what we're seeing. The field is behaving really nicely here.

April was a really nice surprise for us with the amount of completions. And we're looking forward to some follow-up here as the weather has been better and road restrictions are expected to come off. And then we can maybe revisit guidance here a little later in the year, when we have a better grasp of the second quarter's production.

Thanks, Mike. That's helpful.

Thanks.

Jason Wangler, Wunderlich Securities.

Good morning, Mike.

Just curious with the acreage you keep picking up, and I think said about 5,000 or so acres during the quarter.

Are you seeing that ability to pick up acreage kind of in the same areas that you're still drilling? Or are we still kind of all over? I'm just curious of where you're zoning in on the acreage pickups.

As I mentioned a minute or so ago, we're really focusing our acquisition opportunities in the areas with the highest return. A lot of our typical activities with 100 acres here, 200 acres there in the core of the play where we're picking up acreage subject to well proposals. So we're staying really focused on the core.

Some of the acreage that's expiring, we're seeing in Richland County and then on the very eastern edge of the play, acreage we picked up five plus years ago when we didn't fully have a grasp of the delineation of the boundaries of the play.

We're really high-grading our acreage pretty nicely here. So the acreage adds that we're picking up each quarter, we're hydrating and then quickly converting those to held leases.

But we're staying focused on the core. We're not buying any big blocks of acreage, no big AMIs similar to the stuff we've done in the years past out in Richland County with Slawson. Now it's just picking up the core.

That's helpful. Thank you. I'll turn it back.

(Operator Instructions).

Phillips Johnston, Capital One.

Thanks.

Just on the first quarter of CapEx -- I'm sorry if my question is a little obtuse, but I just want to make sure I'm understanding it correctly. The $103 million is about 26% of your annual drilling completions budget, yet you only completed 4.6 net wells in the quarter.

In the release and in your prepared remarks, you referenced accrual amounts attributable to the drilled-but-not-yet-completed wells that occurred in the first quarter.

I'm assuming that that means that the actual CapEx on those well completions did not occur in Q1, will be spent in the future. But from an accounting perspective, you went ahead and allocated those costs in the first quarter. Is that correct?

That's correct.

We had a 9.2% growth in wells in process. Actually, the percentage of those wells in process that were a percentage complete basis actually increased from the fourth quarter of 2013 through the first quarter of 2014.

So not only did you have more wells, but the percentage of the group, as far as percentage complete, increased as well. So it is in that CapEx number. And you stated it correctly; we accrue those costs based on the stage those wells are at.

Okay, got it.

Sorry if you covered this earlier, but did you participate in either of Continental's high-destiny padding that they reported this quarter?

Yes, we're in several of the high-density pads. I don't have any specific data for you on updates on those wells.

We've also been fortunate to participate with Continental on a lot of their lower benches of the Three Forks test. We're really encouraged. But I think high density is something that's going to be defining reserves over time, and that's really exciting for us long term.

I think if I can take this opportunity to say, what we're really most excited about is these new completion designs. Although the verdict isn't completely in, these new completion designs appear to be pretty material to EURs.

We think our operating partners and their innovation, we think they're really on to a step change here in EUR. That's what we're most excited about other than just [technical difficulties] that have started here and what looks like a strong 2014.

Sounds good. Thanks.

Thank you.

That concludes today's question and answer session.

Michael Reger, I'd like to turn the conference back over to you for any additional or closing remarks.

Great.

Thank you for your participation in the call this morning. And your interest in Northern Oil and Gas.

Joe will give you a replay information. And we look forward to talking with all of you again soon. Have a good day.

That concludes today's conference. Thank you for your participation.