Northern Oil and Gas Inc (NOG) 2017 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Northern Oil and Gas, Inc. Third Quarter 2017 Conference Call.

(Operator Instructions)

And as a reminder, this conference call is being recorded. I would now like to introduce your host for today's conference, Mr. Brandon Elliott. Sir, you may begin.

Thanks, Saundra. Good morning, everyone. This is Brandon. We are happy to welcome you to Northern's third quarter 2017 earnings call. I will read our safe harbor language and then turn the call over to Tom Stoelk for his remarks.

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 may discuss certain non-GAAP financial measures, including adjusted net income and adjusted EBITDA. Reconciliations of these measures to the closest GAAP measures can be found in the earnings release that we issued last night.

With the disclosures out of the way, I will turn the call over to Tom.

Thanks, Brandon. Good morning, and thank you for joining our call today. Like previous quarters, I'll start providing some color on our operational and financial results for the quarter, and then we can get to your questions.

Let's start -- let me start off by saying the strong results provided in our earnings release are reflective of the momentum we're beginning to see from the effort the entire Northern team has made over the last year. Our focus on a return base capital allocation process allows us to flex our capital spending, based on the best investment opportunities, while at the same time, remaining disciplined in our balance sheet and liquidity management. We continue to selectively acquire incremental interest in actively developed areas and our recently completed credit facility provides the company a runway to execute on our business plan and benefit for future improvements in oil pricing.

Turning to our results for the third quarter. Production grew 14% year-over-year, and 11% sequentially to reach 15,321 barrels of oil equivalent per day, totaling approximately 1.4 million BOE. What's really encouraging is that the growth in production is a result of 3 key drivers that we expect to be sustainable going forward. These key drivers are: first, improved well performance from enhanced completions; second, increased activity levels on our acreage; and third, our bread-and-butter game of acquiring additional well interest.

This quarter's increased production result was partly driven by high working interest on wells placed into production during the quarter, which helped produce some strong results, 2 notable wells included Continental's Wiley 7-25H and Wiley 5-25H, which we added to production in mid-August. Since coming online, the combined net production from these 2 wells averaged 1,500 BOE per day and increased our daily production during the quarter by 793 BOE per day.

During this quarter, we also began to see increased drilling activity on the Slawson operated acreage in their big [damp] field as well as completion of Marathon's wells in Mountrail County.

Currently, there are approximately 54 active rigs running in North Dakota. Strong activity on our acreage saw us considering to 4.2 net wells during the quarter. Our well elections continue to be focused in the core of the play with approximately 1/3 of this quarter's consent activity being driven by the acquisition of incremental interest in units that we generally already held an interest in. We remain return focused and continued to selectively invest in opportunities that offer the highest rates of return available to us. We estimate that the wells we elected to participate in during the third quarter had a weighted average EUR of approximately 880 Mboe and a weighted average IRR at the date of election of 35%.

Based on the improved results, we're seeing an initial production rise in EURs. We continue to be very optimistic about the composition and quality of our end process well inventory. During the quarter, we added 5.2 net wells to our in-process inventory and reduced that inventory by 3.6 net wells that were added to production. As a result, at quarter end, we had 18 net wells in process, which is our highest level since 2014.

Continental Resources comprised approximately 42% of our net well inventory at quarter end, and the list is complemented by many of the best-in-class operators in the Williston Basin. Clearly, a pace at which our backlog of in-process wells are completed will affect our spending and production levels for the remainder of 2017. Should some of our operators accelerate completions in the fourth quarter, we could see a higher net well addition number, which will result in slightly higher capital expenditure spending.

Based on the current rate of development activities, we are increasing the number of net wells. We now expect to add to production in 2017 to 14 net wells. A higher number of net well additions year-to-date as well as the growth of our in-process well inventory drove higher capital expenditures totaling $40.7 million for the third quarter and $98.7 million for the first 9 months of this year. In October 2017, we added an additional 3 net wells to in-process inventory list. As a result, we currently expect 2017 capital expenditures to total approximately $130 million.

The capital spending increase over our initial plans is driven by a higher number of net well additions to production as well as the growth of our in-process inventory, which we expect will drive strong results in 2018.

Given our year-to-date results, and the increase in the number of net wells, we expect to add to production in 2017, we are raising our annual production guidance to a year-over-year increase of between 5% and 6%. Crude oil differentials during the third quarter of 2017 were $6.22 per barrel below the average NYMEX price and came in slightly better than our expectations. With the Dakota Access Pipeline operational, the overall increase in basin takeaway as lower differentials and we believe that differentials for the remainder of the year will range between $6 and $7 per barrel.

Lease operating expense for the third quarter came in at $8.94 per BOE compared to $8.83 for the same period a year ago, the increase this quarter was largely due to higher processing and saltwater disposal cost. We expect our fourth quarter lease operating expense per BOE to range between $9 and $9.25.

General and administrative expenses were $8 million in the third quarter of 2017 compared to $2.1 million in the third quarter of 2016. The increase was due in part to a $3.6 million nonrecurring charge in connection with the settlement of our former Chief Executive Officer during the third quarter and a $900,000 increase in legal and professional expenses compared to the third quarter of 2016, which was partially offset by a $400,000 decrease in cash compensation expense. In addition, general and administrative expenses in the third quarter of 2016 were reduced by a $1.8 million reversal of noncash compensation expense in connection with the termination of the employment of our former Chief Executive Officer. We expect our fourth quarter of 2017 general and administrative expense to range between $3 and $3.25 per BOE.

On November 1, 2017, the company entered into of $400 million credit facility with TPG Sixth Street Partners. We're excited about this relationship, not only from a lending perspective, but the strategic opportunities this new relationship opens up for Northern.

The company used $300 million of the $400 million available on this facility. With $100 million remaining, committed and available under delayed draw basis for 18 months. The new credit facility replaced Northern's bank facility, which was due to mature on September 30, 2018. With the company's maturity and liquidity profile vastly improved, the new credit facility provides a liquidity runway to execute on its development activities, make acquisitions that further the company's business plans, potentially repurchase debt or equity securities if it is in the best interest of the company and shareholders and we all hope to benefit from the future improvement in oil pricing.

Our available liquidity on November 1, 2017, was approximately $235 million, which included the $100 million of delayed draw capacity under the new credit agreement. Our new credit facility requires us to maintain certain levels of hedging over a rolling 3-year forward period. As you can see in the earnings release from yesterday, that we have already layered in a significant amount of that hedging. We will continue to add hedges to manage our commodity price risk and protect our future cash flows from downside risk.

In conclusion, we'll continue to use our flexible capital allocation process to protect the value of our assets and seek the highest rates of return available to us. The increases that we're seeing in well productivity and EURs give us confidence for 2017 and beyond. We have great momentum as we approach 2018, and our high-quality assets and return focused strategy provides a solid foundation to increase shareholder value.

With that, I'll turn the call back over to Brandon.

All right. At this time, we will turn it over to the operator for Q&A. Saundra if you could please give the instructions for the question and answer period of the call.

(Operator Instructions) Our first question comes from the line of Neal Dingmann with SunTrust.

Tom, a question, follow-up. First, just a quick one. On differentials, you mentioned, I think, around, 6-ish. Seems like there are a few of the operators who are suggesting to something materially lower than that. Are you just staying conservative there? Or is there potential for some upside?

No. I think, there's some potential for upside. I think our differentials in September came in at $5.78 kind of, range. They have been trending down through the quarter. Typically, or historically, anyway, we've seen a little bit of uptick in the fourth quarter and that's why we, kind of, set the range where it was at, Neal. But definitely, I think there's -- we are seeing a trend down and there is some upside there.

Okay. Now post the refinance, which is good to see, then you guys certainly have now more optionality, I would call it. Are there -- are you just targeting -- Tom, I'm just wondering sort of, your process, are you targeting sort of, certain areas around that McKenzie, Williams area? Are you targeting certain operators? I'm just trying to look at the strategy now that you're in a bit better position than the defense position you guys have been in for a while?

Well, I think you're pointing out. Those are 2 very high IRR areas, both Williams and McKenzie, so a lot of what we're focusing on is in that area, because, as you know, Neal, a lot of our decisions or really all of our decisions are really rate-return kind of, driven. We're -- you've seen a build in our D&C list, really, since the beginning of the year and it is really been driven by a lot of activities, certainly, in McKenzie, a little bit is done, as well as Mountrail and Williams. But we're excited about that. In some of the other calls, you heard Continental talk about the record-setting wells. The Wileys were in. Our D%C list has 2.5 net wells still in that unit with another, almost net well is directly offsetting that. Continental has had extremely good results. We are very exposed to them as I commented on in the script about 42%. With Whiting, we've got some offsetting wells to the Kuala 3,125 that they commented on, I think, in their call about 1 million or 1,500 Mboe, so we got 5 wells directly offsetting that. So we have been, through the year kind of, setting it up. And in my comments, in the script, I talk about the momentum and I just want to stress kind of, that word is something that the team has worked very hard at, over the year kind of, accumulating interest and we ended up the quarter with about 18 net wells. We had some opportunities in October, and really, I referenced in the call script as well. We added about 3 net wells to the D&C list at that point in time. So you're -- like I said, the composition is probably the best I have seen, since I have been here, as far as the quality and the possible upside with respect to those wells.

And lastly, just, as far as the working interest, is that staying the same? Or for some of these key areas, are you able to start to step up and take a large position? Or is that -- the interest remaining the sort of, same? I want to know...

No. To your point, I mean, it's a good point. Is that -- in those areas, we talk about our bread-and-butter ground game and that's essentially going in and having an opportunity to roll up incremental interest in DSUs that we already participate in or we want to participate in. So in general, you saw some higher working interest, certainly, on the Wileys. And you took a look at the working interest, and some of the offsetting there, they're higher. I think, with 3,000 gross wells, you're not going to necessarily see the uptick in our average working interest in total, but certainly, starting to take a little bit higher interest in some of those DSUs.

(Operator Instructions) And I'm showing no further questions. I would like to return the call to Mr. Brandon Elliott for any -- I apologize, one question has just come through from the line of Nate Streicher with AmTrust Financial.

A quick question for you. Why did you guys use TPG for this new loan as oppose to possibly going back to your bondholders for the refinancing?

I mean, we can check that out. Go ahead.

So I mean, I know was the unsecured bondholders had approached the company to kind of, talk about helping with the cap structure, but then you are with TPG, and I don't believe it's one of your unsecured bondholders, I was just curious about that.

We did a fairly extensive process in the market where we contacted several providers. We got a number of different proposals. And we felt that -- we had some excellent representations through that process. The company was advised of the process by both Evercore and Jones Day. and they presented the full information and analysis about the potential transaction. Really after full or due consideration, the company concluded that the proposal received from TPG was the best and most exercisable transaction in light of the company's other alternatives.

Thank you. And I'm showing no further questions. And I'd like to turn the call to Mr. Brandon Elliott for any closing remarks.

All right, Saundra. We appreciate everyone tuning in. If anyone's got any follow-up questions, did not want to ask them on the call, please follow up with us at your convenience, and if that, Saundra I will turn the call back over to you to give the replay instructions.

Ladies and gentlemen, thank you for participating in today's call. A replay of today's call will be available at 1 p.m. Eastern Time today and will be available until November 16, at 11:59 p.m. Eastern Time. To access this recording, you may dial (855) 859-2056 or (404) 537-3406 and provide today's conference ID of 3696446. This does conclude the program and you may all disconnect. Everyone, have a great day.