Northern Oil and Gas, Inc.
Q3 2014 Earnings Call Transcript

Published: 7 Nov 2014

[Operator:]

Good day and welcome to the Northern Oil and Gas Incorporated Third Quarter 2014 Earnings Conference Call. Today’s conference is being recorded. And at this time, I’d like to turn the conference over to the Executive Vice President of Corporate Development and Strategy, Mr. Brandon Elliott. Please go ahead, sir.

[Brandon Elliott:]

Thanks, David. Good morning, everyone. We’re happy to welcome you to Northern’s third quarter 2014 earnings call. I will read our Safe Harbor language and then turn the call over to Mike Reger, our Chairman and Chief Executive Officer, for his opening comments. And then, Tom Stoelk, our Chief Financial Officer, will walk you through the financial results for the quarter. Please be advised that our remarks today, including the answers to your questions, may include forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from the expectations contemplated by these forward-looking statements. Those risks include, among others, matters that we have described in our earnings release as well as in our filings with the SEC, including our Annual Report on Form 10-K and our quarterly reports on Form 10-Q. We disclaim any obligation to update these forward-looking 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 measures to the closest GAAP measures can be found on the earnings release that we issued last night. With the disclosures out of the way, I will turn the call over to Mike.

[Michael Reger:]

Thanks, Brandon. Good morning and thank you for joining our call today. This was another very solid quarter for Northern, as the momentum, we saw building in the second quarter continued throughout the third quarter. Robust completion activity allowed us to grow production 8% sequentially and 26% year-over-year. Drilling activity continued at a rapid pace. And as a result, at the end of the third quarter, we are participating in a record 359 gross, 25 net wells in process, meaning they were active wells that were drilling, completing or waiting completion at the end of the quarter. Of our wells in process at quarter-end, 93% remain in the big four counties of Mountrail, McKenzie, Williams and Dunn. The county concentration has been an important theme over the past year, as these four counties have historically given us our highest returns. We continue to use a return-focused capital allocation process to high-grade our portfolio of producing wells, seeking to ensure that each well we participate in, exceeds our internal rate of return thresholds. We continue to see a significant number of investment opportunities every day, in the form of well proposals and additional acreage opportunities. And determining whether or not to participate in a well, we use our wealth of data from other wells in the Williston Basin to generate an expected rate of return, when that data – when that expected return doesn’t meet our internal thresholds; we simply opt out of the well and save our capital for higher return projects. It is important to note, when we choose not to participate in a well, we don’t lose any of our acreage or the ability to participate in additional wells in the drilling unit. In fact, we still benefit because our acreage in that drilling unit becomes held by production regardless of our non-consent. Our disciplined capital allocation process continues to drive our improved average well productivity. Based on the strong activity levels I mentioned earlier and this improved well productivity, we are raising our full year 2014 production guidance to an increase of 25% over 2013 production, which is the high end of our previous range of 20% to 25%. As many of you know, Northern is the largest exclusively non-op participant in the Bakken and Three Forks play with a leasehold position of approximately 185,000 net acres. What some of you may not fully appreciate, is, the value of our business model when we are seeing downward bias volatility in the commodity markets. Northern is uniquely positioned to reduce its drilling CapEx quicker than our operating partners. As I mentioned earlier, we received well proposals daily and as a non-op we afforded the opportunity to analyze those proposals on a well-by-well basis, to determine what investments will generate the highest returns. As part of this process, we monitor commodity prices real-time and, if appropriate, adjust the pricing we use to estimate expected returns. The ability to tailor our capital allocation process quickly and without any associated frictional costs due to long-term rig contracts, or frac crude commitments or [indiscernible] With the volatility we’ve seen recently in oil prices, we are extremely pleased with the capital flexibility that our non-op model provides. Not to mention the extensive hedge book we’ve built to protect our cash flow. Tom will talk more about this in a few minutes, but lastly before I hand it off to Tom, I want to share some encouraging data related to the new completion techniques being implemented by many of our operating partners. We believe these techniques are leading to meaningful improvements in IP rates, and not necessarily just in one particular area of the play. In fact, we’ve observed significant improvements from the new completion techniques being deployed outside of the core of the play as well. Based on our internal analysis, we’ve seen an approximate 30% uplift in 30-day IP rates for wells using the new completion designs. Many of these wells are new to come on-line, but the preliminary results are very positive. At the end of the third quarter, approximately one-third of our wells in process were using some variation of the newer completion designs, and we believe this will increase throughout 2015. With that, I will turn the call over to Tom Stoelk, our CFO for a rundown of the financials.

[Thomas Stoelk:]

Thanks, Mike. For the third quarter we reported net income on a GAAP basis of 58 million or $0.95 per diluted share. Our adjusted net income was 15.6 million or $0.26 per diluted share and adjusted EBITDA for the third quarter totaled 81.4 million. During the third quarter, our total production volumes were approximately 1.5 million Boe, or an average of 16,448 Boe per day, which was up 26% as compared to the same period last year. On a sequential quarterly basis, production volumes increased 8%. The strength of the overall financial results of third quarter were clearly driven by increased production levels. During the third quarter, we added 13.8 net wells to production, bringing our total producing well count to 177.5 net wells. One factor that contributed this quarter to production growth, was that almost all of the producing well additions this quarter occurred in the core counties that Mike referenced earlier in his comments. Our oil and natural gas sales reached 119.2 million during the third quarter, which was an 11% increase as compared to the same period a year ago. Our average oil price differential to NYMEX WTI benchmark was $12.92 per barrel in the third quarter of 2014 which compared to $12.25 per barrel last quarter and $9.04 per barrel during the third quarter of 2013. In discussions with some of our operators are indicating that Octobers oil differentials are averaging in the $13 to $14 range. During the third quarter of 2014, our realized price per barrel of oil equivalent after reflecting our settled derivative transactions was $74.13 per Boe, which was down approximately 6% compared to last quarter due to lower oil prices during the back half of the third quarter. As a result of forward oil price changes, we had a non-cash mark-to-market derivative gain of 68.6 million in the third quarter of 2014, compared to a non-cash loss of 29.4 million in the third quarter of 2013. Settled derivative losses in the third quarter of 2014 amounted to 7 million, which compares to an 8 million loss in the third quarter of a year ago. Production expenses increased 1.7 million from last quarter and reached 14.7 million. On a per unit basis, the average production expense increased to $9.73 per Boe. Despite the quarterly increase in a per unit basis result from high workover expenses, water hauling and disposal costs. During the quarter, certain of our operators, use the opportunity to perform workovers on offsetting wells that we’re shutting due to completion activities on new pads. Given our large inventory of in-process wells, we expect that some of our operators will continue to workover offsetting wells that are shut into facilitate completion activities on the new drills. We’re currently estimating that production expenses on a per unit basis will be approximately $10 per Boe during the fourth quarter of 2014. Production taxes totaled 12.1 million during the quarter, or approximately 10.1% as a percentage of oil and gas sales, which was the same percentage experienced last quarter. The company’s production tax rate is trended slightly higher, due to a decreased weighting of low revenues on wells still receiving tax exemptions. Upon exploration, these production tax exemptions in North Dakota, the rate increases to the standard of 11.5% statutory rate. As the mix in our production base changes, we expect our average production rate as a percentage of oil and gas sales; will continue to trend higher throughout 2014, likely averaging in a mid-10% range for the full year of 2014. General and administrative costs were $4.7 million in the third quarter of 2014 compared to $4.2 million for the third quarter of 2013. On a per unit basis, our general and administrative expenses per Boe decreased 10% when compared to the third quarter of 2013. Depletion, depreciation, amortization and accretion, was $45.6 million in the third quarter of 2014 or $30.17 per Boe and that compares to a $32.1 million or $26.74 per Boe in the third quarter a year ago. The depletion rate per Boe of $30.02 has remained unchanged in 2014. Our capital expenditures during the quarter totaled $124 million. The breakdown of the total is as follows

[Operator:]

Thank you. [Operator Instructions] We’ll take our first question from Scott Hanold with RBC Capital.

[Thomas Stoelk:]

Good morning, Scott.

[Scott Hanold:]

Mike, could you talk a little bit more regarding your threshold as you look at wells, and how does the impact of oil price have on that obviously with oil coming down? What do you use to make that assessment?

[Thomas Stoelk:]

It’s fluid, Scott. But generally speaking we’re looking at a minimum internal rate of return threshold of a 20% to 25% IRR. And as we adjust our price decks in our IRR analysis, based on the expected EUR of the well, and the cost of well, that’s going, obviously move the internal rate of return up or down, depending on which price deck we’re using. So, as we’ve been able to respond over the last, call it, six weeks to the oil price volatility, we’ve been able to adjust our price decks quickly in real-time, which we’ve seen have an effect on the percentage of growth in that wells that we’ve non-consented starting in, call it, October.

[Scott Hanold:]

Okay. So just to clarify then do you use the strip price, it is like 12-month strip or do you use longer strip? And then could you quantify like – I don’t know, call it, in the last month approximately how many wells you may have non-consented that – say six months ago you wouldn’t have because of oil price?

[Thomas Stoelk:]

So, to give you some color, we use several pricing scenarios when we we’re looking at our AFEs. We used strip. We use a blend of our – the strip in our hedge book and then we use a flat price that we keep constant. So we can test for, look back internal rate of return analysis in the future. So that’s the way we’re looking at that. To give you some color in that – and in anticipation of this question. Throughout the third quarter we non-consented, about 12% to 15% of the growth in net wells that we received as well proposals or AFEs and in October we non-consented over 25%. So you can see the immediate response to our change in price deck and what that meant for us. And that’s again is the strength of the non-op model in times of commodity price volatility and market volatility.

[Scott Hanold:]

So six months ago, do you think a lot of those wells would have met the hurdle rate? Then again is it based on oil price?

[Thomas Stoelk:]

I think our consistent – we’ve been consistently over the past call it two years non-consenting in the neighborhood of 10% to 15%, probably closer to 10%. And in times like this when we can really sharpen our pencil and pair back CapEx or could pair back – or focus on the highest IRR opportunities. We think it’s probably going to be in the 25% range for the near-term but over the past few years it’s probably been in the 10% of our gross in net wells that we see, we elect to go non-consent.

[Scott Hanold:]

Okay, good thanks. And a follow up question when you look at your acreage acquisitions, it continues to be fairly robust. So two questions one, with obviously the decline in oil price and I know you all added that Denver office and staff there, do you think you’re going to be able to take advantage, or have you seen some more opportunities come to you? And the second question is, your total acreage did come down, can you, again, remind us on what stuff is falling off and where you are adding new acreage?

[Thomas Stoelk:]

Sure. In the third quarter the acreage that fell off was in southeastern Dunn county and southwestern Richland county in Montana. So acreage that we had on our schedule that as development slowed in those areas, they began to fall off. The acreage that we added, which was about equal to the acreage that expired in the third quarter because we didn’t drop materially, we are still right around that 185,000 acre range, was primarily in Williams McKenzie, in those particular areas. So to get to the second part of your question, we have seen a fairly material increase in deal flow. However, I guess, really the only thing I can say, is that, we’re being very selective in the opportunities we’re acquiring. And we are monitoring movements as it relates to price discovery given the volatility in the commodity market. So knowing us as well as you do, Scott, you know that we’re going to be monitoring both the market and the environment as it relates to our acquisition.

[Scott Hanold:]

No I appreciate that. And it is good to see you’re high grading that inventory.

[Thomas Stoelk:]

Yes, thanks, Scott.

[Operator:]

We will take our next question from Ryan Oatman with SunTrust.

[Ryan Oatman:]

Nice production ramp in 3Q allowing you to take up guidance for the year. I am wondering, how we should take about 4Q, one hand it seems like two net wells in October maybe less than you had in July or October last year but on the other hand huge backlog of 25% net wells in process should we look for production to be kind of, slightly down sequentially before rebounding in 2015 or is that not the right way to think about it?

[Michael Reger:]

This is Mike. I would say that I would just stick to our guidance of 25% year-over-year growth for 2015.

[Ryan Oatman:]

Okay. That’s helpful. And then looking out to 2015 and, kind of, building on the last kind of, line of questioning. I guess if this year’s D&C budget is 400 million, don’t want to pigeon hole you into anything at this point, but if you had more kind of, non-consents, is it fair to say that that budget’s kind of, looking similar to this year, maybe down a little bit? How are you thinking about CapEx next year?

[Michael Reger:]

I would say that the only way to answer that at this time not knowing what the environment’s going to look like throughout the fourth quarter and into the beginning parts of ‘15 especially through the winter. I would say that from a CapEx standpoint, it would be bias down. However, we are going to refrain from giving any additional color on 2015 CapEx, right now.

[Ryan Oatman:]

Sure. Sure. And then I know you’ve got the nice hedge book next year, but also you guys having a good shy about buybacks. What are your thoughts on increasing buybacks versus CapEx in this commodity price environment, should you have some incremental dollars available to you that – you might have been thinking we’re going into the drill bit before?

[Michael Reger:]

Yeah, thanks. Buying back stock is certainly something that remains on our radar. As you know since August of last year we bought back about 5% of our stock under our existing stock repurchase program. Our capital allocation decisions, it’s something that we want to always consider in the context of the current situation. We’ll continue to evaluate it as we always have with an eye on a few factors, mainly our current liquidity position which is strong, our hedge book which is extensive, the price of our stock, the volatility in the markets and also other opportunities to invest in our capital. Like I mentioned to Scott earlier with price discovery on assets, we can acquire and be strategic around. Beyond that I guess I’m not going to be too specific other than to say it’s – as you know it’s always been on our radar and we have purchased stock in the last year. We purchased 5% of our stock back. So it’s going to continue to be on our radar.

[Ryan Oatman:]

Well, I appreciate that. It sounds like you guys have a lot of flexibility and ability to respond quickly to the oil prices. So I’ll hop back in the queue.

[Michael Reger:]

Great, thanks a lot.

[Operator:]

Our next question comes from Andrew Smith with Seaport Global.

[Andrew Smith:]

Hi, guys. Congrats on your quarter in Q3. For Q4 production and I guess, just the implied Q4 number from your 2014 guidance, how much weather downtime do you have baked into that and how does weather look versus your expectation so far in the quarter?

[Michael Reger:]

This is Mike. I think we are just looking at the Q4 as just another normal quarter for us. Q4 is the start of the winter so we’re just looking at the current activity in process, the age of the wells in process, and just making, basically, a fair assumption around our guidance. And so, we’re really just going to emphasize that – to stick with our 25% year-over-year guidance. That should just lead you to the number.

[Andrew Smith:]

Thanks.

[Operator:]

[Operator Instructions] We’ll take our next question from Adam Leight with RBC Capital Markets.

[Adam Leight:]

Thanks, Mike, for your commentary around strategies, a couple of additional questions on spending. First what kind of a message have you gotten so far from some of your private operators? And how do you think your budget process is working compared to say a public company process?

[Michael Reger:]

Yeah. I think that we’ve been visiting with all of our operators, both public and private. And, I think like everybody is generally on the same page and that in times of commodity price volatility like this, to be very strategic about deploying capital to the highest return projects. I guess, I haven’t heard anybody deviate from the general strategy of, now is not a time to be outside of the core holding acreage, obviously. So I think we’re pleased with the response across the board. And I think the Bakken and all of the participants in the Bakken are going to respond really well to this.

[Adam Leight:]

You don’t have a sense that some of those guys might move a little more cautiously than some of the public companies or any differently at least at this point this?

[Michael Reger:]

I think the answer is, it’s just too early to tell what everybody’s plans are. Rest assured everybody’s eye is on the ball right now.

[Adam Leight:]

Secondly on liquidity, you are partly into your revolver under the circumstances how are you looking at – what kind of minimum liquidity you would like to maintain during this period of volatility?

[Brandon Elliott:]

I think that’s a great question. Personally I would always like to have 50 million to 70 million of kind of available liquidity. So that’s kind of how I would answer that.

[Adam Leight:]

Did you say 70 billion –?

[Brandon Elliott:]

No 1 million. Didn’t I say billion?

[Michael Reger:]

We’d love 70 billion, but he said 70 million.

[Brandon Elliott:]

A billion would be nice.

[Adam Leight:]

I am kidding. And then lastly, as you make your spending decisions, I know you talked a little bit in answering Scott’s question about the price tax and all that. Do you ever consider like the MLP’s do of hedging individual investments? If you can make a well decision or any series of well decisions based on the current strip and then locking it in, is that something you think about doing?

[Michael Reger:]

I think our strategy around hedging has been consistent over the past really five plus years, maybe longer. And that we’ve always had a fairly robust hedge book. That’s reached out approximately two years. So with the volatility we’ve seen recently, I would just say that as per the design of our hedging strategy, as oil prices dropped materially over the past two months, we are fortunate that we have a fairly long duration in our hedge book. And that’s the nature of the strategy. We look at ourselves more as manufacturers of oil than strategic explorationist. So we’re going to continue to – we’re going to continue to be diligent with our hedge book and as it relates to our hedge book and commodity markets, we’re going to make our capital decisions that way. But the strategy that you are mentioning is a good strategy. We are just going to stick with our strategy for now.

[Adam Leight:]

And one last question for me. Do you have a sense given the way your CapEx works? What you think your spending would have to be, just to maintain production at current levels?

[Thomas Stoelk:]

A hip shot on it, Adam, would probably be around half of the wells that we drill right now probably around 22 wells we are expecting to drill 44. 22 would have a real modest, probably wouldn’t be flat. But you are talking in the 1% to 2% range. And obviously it depends on a lot of factors. But a very broad answer to your question would be about half.

[Adam Leight:]

Okay, that’s great. Thank you.

[Michael Reger:]

Thanks.

[Operator:]

Your next question comes from Phillips Johnston with Capital One.

[Phillips Johnston:]

Hey guys thanks. Just a follow-up on the questions around fourth quarter production if you look through 25% guidance sort of implies around 2% decline in the fourth quarter from the 16.4 a day average in the third quarter. I think in the release you’d said you are on pace to meet your 44 net well goal for the year, what sort of implies 4.5 net well completions per month over the next couple of moths here? So, my question is that are you just being conservative here or do you really expect the decline in the fourth quarter?

[Brandon Elliott:]

This is Brandon. I think the big thing to focus on is we usually give in our press release kind of the current month’s additions. And I think we’re 2.3 net wells for October, as Mike mentioned with winter still in front of us. I think that’s it’s just an appropriate place to be. And yeah, we certainly understand it implies a 2% decline, but given all we’ve got in front of us. And as Tom mentioned in his comments earlier, you’ve had some shut in production as people are around completing additional pads. And so, we’ve got – we’re making some assumptions on how much production we lose as we see pads being brought on and adjacent production being shut in. And like Mike said, winter is still in front of us.

[Phillips Johnston:]

Yeah, does make sense. Thank you.

[Brandon Elliott:]

Thanks.

[Operator:]

Thank you. We have no further questions in queue. At this time, I’d like to turn the conference over to Mr. Mike Reger for any concluding remarks.

[Michael Reger:]

Great. Thank you for your participation on this call today and your interest in Northern. David, will you give the replay information, please, and we look forward to talking with all of you again soon. Have a good day.

[Operator:]

Thank you. That does conclude today’s conference call. The replay will be available about two hours after the conference call. And you may dial into the replay by dialing 1-888-203-1112 and referencing the passcode you used to enter the conference. Thank you for your participation.