Continental Resources Management Discusses Q4 2013 Results - Earnings Call Transcript

| About: Continental Resources, (CLR)

Continental Resources (NYSE:CLR)

Q4 2013 Earnings Call

February 27, 2014 11:00 am ET


John Kilgallon

Harold G. Hamm - Executive Chairman, Chief Executive Officer, Chairman of Finance Committee and Member of Nominating & Corporate Governance Committee

Winston Frederick Bott - President and Chief Operating Officer

John D. Hart - Chief Financial Officer, Principal Accounting Officer, Senior Vice President and Treasurer

Richard E. Muncrief - Senior Vice President of Operations

Jeffery B. Hume - Vice Chairman of Strategic Growth Initiatives

Jack H. Stark - Senior Vice President of Exploration

Steven K. Owen - Senior Vice President of Land


Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Andrew Venker - Morgan Stanley, Research Division

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Brian Singer - Goldman Sachs Group Inc., Research Division

Marshall H. Carver - Heikkinen Energy Advisors, LLC

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

Andrew Coleman - Raymond James & Associates, Inc., Research Division


Good morning, and welcome to the Continental Resources Fourth Quarter and Full Year 2013 Earnings Conference Call. I would now like to turn the call over to Mr. John Kilgallon, Vice President of Investor Relations. Please proceed.

John Kilgallon

Thanks, Vanessa, and good morning, and welcome to the Continental Resources Fourth Quarter and Full Year 2013 Earnings Conference Call. Joining me on the call this morning, with prepared remarks, will be Harold Hamm, our Founder, Chairman and Chief Operating Officer; Rick Bott, President, Chief Operating Officer; and John Hart, Senior Vice President and Chief Financial Officer.

Also available during the Q&A sessions are other members of the Management team including Jeff Hume, Vice Chairman of Strategic Growth Initiatives; Jack Stark, Senior Vice President of Exploration; Rick Muncrief, Senior Vice President of Operations; Steve Owen, Senior Vice President of Land; and Warren Henry, Vice President of Research and Policy.

In conjunction with the earnings press release and our call this morning, we have posted a summary presentation on the Continental website at as a reference tool. This presentation can be found in the For Investor section of our website. It is also posted within the web portal for your reference.

Today's call will include forward-looking statements that address projections, assumptions and guidance. Actual results may differ from those contained in the forward-looking statements. Please refer to the company's annual report on Form 10-K filed this morning with the Securities and Exchange Commission for additional information regarding these statements and risks.

Also in today's call, we may refer to EBITDAX, cash margin, adjusted net income per diluted share and PV-10. For a reconciliation of EBITDAX to GAAP net income and operating cash flows, a description of the calculation of cash margin, a reconciliation of adjusted net income per diluted share to GAAP net income per diluted share and a description of PV-10, please refer to the summary presentation materials I mentioned earlier that can be found at our website

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

Harold G. Hamm

Thank you, John. Good morning, everyone, and thanks for joining us on the call this morning.

In 2013, the Continental team delivered another year of record performance, closing with a strong fourth quarter despite weather conditions and challenges in North Dakota and Montana.

We delivered on our commitments hitting key targets in terms of production, growth, capital efficiency, exploration success and proved reserves growth.

In just a moment, Rick Bott and John Hart will review our 2013 report card, specifically noting our 2013 goals and just how we achieved them. However, since this review of 2013, I'd like to think with you strategically for a moment about Continental Resources. We've built a leading E&P company with an exceptional track record of exploration success in the Sayer [ph] Hill, Bakken and SCOOP plays with more to come.

Since our initial public offering in May 2007, we've created outstanding value. In the process, we've participated in a historic energy renaissance in the United States that is literally changing our entire world.

This renaissance will have a profound positive impact on U.S. Energy Security and our economy. Continental is increasingly and rightfully recognized as one of the key leaders in American energy renaissance given our leadership in these strategic plays. However, apart from Continental's role as energy leader, how does the company continue to rank as the investment opportunity? What is the state of the company's investment thesis?

We see an outstanding opportunity to continue generating exceptional shareholder value for you. To understand our view, let's consider 4 points as we close 2013 in the context of the first year of our new 5-year plan.

Point one. Continental remains a high-growth company committed to exceptional production growth. Last year, we increased production, 39%, almost entirely through the drill bid and we're on track to achieve our 5-year goal of tripling production by year end 2017. That means by year end 2017, production should be roughly doubled what it is today. We're focused on strong profitable growth.

Point two. We have a tremendous growth platform, a multi-decade drilling inventory and premier oil and liquids concentrated resource place. We continue to add to our key leasehold positions in 2013, and now have more than 1.2 million net acreage in the Bakken.

As a leader in the play, we are transitioning in the full development mode so we can maximize the payback on our highest return lease holds. This is the Ears Back program in Antelope.

In SCOOP, we increased our leasehold almost 404,000 net acres at year end 2013. We're seeing very strong results as we delineate the play with exploratory

Bakken and SCOOP exemplify our focus on the superior value of oil and liquids, although the run up in natural gas prices in recent weeks demonstrate the option value we have if natural gas prices strengthen in future years.

SCOOP returns should be even stronger in future years if we get the same higher natural gas prices. Still, our value cornerstone is oil. 2013 production was 71% oil and our year end 2013 proved reserves were 68% oil.

Point three. Continental is an exploration company, it's just in our DNA. In 2008, with the first 3 explorers, the first bench of the Three Forks in previous commerciality. In 2013, we repeated this by exploring with productivity and density test to lower benches in the Three Forks.

As our Hawkinson density test demonstrates, the Three Forks package is larger than anyone knew just 2 years ago. And it should be a significant contributor to our production in proved reserves growth in the years ahead.

Exploration is also the key to SCOOP. In 2012, at the time we were clearly executing so well in the Bakken, many asked why Continental is spending CapEx on the new geologic concept in the SCOOP and other plays. The answer is now clear.

As explorationists, we're always looking for the next opportunity to apply our experience in new technology to create value that SCOOP fits the bill.

SCOOP today is recognized as tremendous additional growth platform, and we're more excited than ever as we delineate SCOOP to the South and expand our footprint into play. SCOOP well economics are on par with the Bakken, and we're just ramping up our extended lateral growing program here in Oklahoma, which we expect will boost return further.

In addition to these 2 cornerstone plays, we're actively working on new opportunities to acquire experience in lays drilling and completion technologies to new growth opportunities.

Finally, point four. Our business model is focused on profitable growth by maximizing returns and cash flow.

One element this effort involves operating excellence, constantly working to operate more efficiently and at lower costs, while challenging ourselves to better our safety and environmental performance.

As noted, we're exploring not only with the drill bid, but through the application of new technology. 2013 was a tremendous year on all counts. Our teams are developing and managing new markets in maximizing the value of our production. They are working to deliver as much value as possible from every barrel in Mcf to the bottom line. We are continuing to work to develop additional new markets for oil and natural gas production.

So we believe Continental's value creation opportunity is as strong as ever. Our current 5-year growth plan is just the beginning of what we see as a multi-decade growth trajectory based on premium inventories, strong production growth, strong cash flow growth and operating excellence.

We're proud of Continental team's 2013 achievements, which translate directly and increase shareholder value.

We had some tough weather challenges towards the end of 2013, but we're a longtime player in North Dakota and we're not complaining about the weather. The extended cold weather brought natural gas prices out of the door into where they're respectful again and prices maybe there for a while, considering storage. So we're not complaining.

So now the key question is, what's next for Continental? We'll be reporting our progress to you through the remainder of the year. But please make plans for our 2014 Investor Day, which we're tentatively scheduling for around mid-September again in Oklahoma City. Stay tuned as we get closer and announce the date, to put on your calendars. It will be a content-rich download on our key exploration and development projects and growth strategy, so you will certainly want to attend.

With that now, I'll turn the call back over to Rick. Rick?

Winston Frederick Bott

Thanks, Harold. He mentioned in the report card in terms of 2013 as a whole, the Continental team certainly delivered it's A game again this year.

We set out to grow production 35% to 40% over 2012 then increased that goal to top of the range. Final results, 39% year-over-year production growth.

We ended 2013 on a strong note despite challenges in December with severe winter weather as we discussed in our February 6 press release.

Production of 144,250 barrels of oil equivalent per day for the fourth quarter, was 35% above the year-ago quarter and 2% above the third quarter of '13.

Currently, productions recovering nicely as now approximately 150,000 barrels of oil equivalent per day. Crude over here reserves at year end '13 reflected strong drilling programs in the Bakken and SCOOP this past year. We reported record proved reserves of 1.08 billion barrels of oil equivalent, a 38% increase over year-end 2012.

The Bakken now accounts for 68% of proved reserves and our drilling acceleration in SCOOP has increased its reserve contribution to 20% of proved reserves in less than 2 years.

In value terms, PV-10 for our total proved reserves was 22 -- 20.2 billion at year end 2013, a 52% increase over the PV-10 of 13.3 billion at year end '12.

We're solidly on track to achieve our 5-year growth targets with 1 year in the bank.

With regards to our 2013 highlights, I'd like to concentrate on several significant achievements in exploration and operations. What we started in 2013 will continue to have impact and be key catalyst in our 2014, '15 growth picture.

First, we set out in late 2012 to implement an ambitious 22-well Lower Three Forks exploration program to demonstrate commercial productivity across the Bakken play in North Dakota. The other part of the program was 4 multi-well density drilling tests to help us determine optimal well spacing in the Middle Bakken, first, second and third benches of the Three Forks.

We completed all 22 productivity wells and are now monitoring production history to build decline client curves for the lower benches.

In the meantime, work continues on the density testing. In November 2013, we announced initial results from the first test, the Hawkinson project in Dunn County. The Hawkinson project involves 3 legacy wells in the Middle Bakken and first batches of Three Forks and 11 new well space 1,320 feet apart within zone and offset vertically 660 feet.

The new wells are in the Middle Bakken, first, second and third benches of the Three Forks.

Based on the first 120 days of production, average production for 12 of the 14 wells is on a trend approximately 50% higher than the company's 603 barrels of oil equivalent model for the North Dakota Bakken.

The 2 exception wells are in the TF3 zone. They were recently put on pump and are producing on a trend below the 603 barrels model and improving.

Given the early nature of the production, these trends, of course, could change over time.

The next 3 density tests are being completed, the Tangsrud, Rollefstad and Wahpeton. We had hopes to report initial results for the Tangsrud and Rollefstad on this call, but the severe winter weather delayed that schedule. These 2 projects, which are testing again the 1,320-foot spacing should be ready to report on our May earnings call, if not earlier.

Initial results from the Wahpeton, which is testing the 60-foot spacing between wells were also delayed and will likely be ready by mid-year.

Based on our positive results to date, we've begun drilling 3 additional 660-foot spacing density test in the Hartman, Lawrence and Mack units, which are on the slide, supplemental to this presentation.

So we're very pleased with our density testing program. The Hawkinson area in Dunn County was a good test and the location was strong production potential.

Based on the results from all 7 density tests, we plan to be ready next year to accelerate full-field development in multiple areas of the play. However, we received a lot of questions since our announcement last night, so let me pause just a moment to comment on the deeper benches to answer some of these questions.

I guess, I didn't realize that Hawkinson had quickly become such a household name. But testing these deeper benches has not been about whether they meet our 603 model, some do and some don't. But on average, they fit the distribution of other wells in a given area.

The key for us is that we have established commercial production over a very large area. It's always been to define the component parts of the petroleum system to determine how best to proceed with full-field development. So we cost-effectively get the most out of these reservoirs.

We believe future technology advances, as well as efficiency gains will only increase the commerciality of these zones within this large footprint.

So it's also important to understand where we are in our overall Bakken exploration program, so let me step back for a moment and provide some context.

We're nearing the end of really a 6-year process, where our primary goals are to expand the play geographically and vertically, to de-risk of growing leasehold position and to hold core leasehold by production. Information gathering and de-risking has driven this process. We are now beginning to shift into full-field development starting with Antelope, as Harold mentioned, where we have more opportunity to truly maximize efficiencies and rates of return.

Now looking -- again, looking back over the same period, all Bakken operators needed to build up execution capability including drilling rig fleet, service providers, train new crews, construct gathering and takeaway capacities, as well as build basic infrastructure for rapidly growing communities and a growing workforce. There were a lot of growing pains to get through.

These macro issues are behind us now. The industry and infrastructure have, for the most part, caught up with the Bakken. Drilling rigs have leveled off at 180-or-so combining in Montana and North Dakota. Gas processing capacity is catching up, rail transportation systems have been built out and additional pipeline takeaway capacity is on the horizon.

Basin-wide production can, therefore, continue to grow because of all of this investment. This makes huge a difference in terms of communities in northwestern North Dakota. For example, with more gathering capacity, we can get many trucks off the road and reduce congestion.

More gas process capacity enables the industry to reduce flaring. But the progress we've made is also critical in terms of optimizing efficiency, safety and environmental stewardship in our operations. We're making huge strides.

Moving into full-field development in Antelope provides yet another opportunity to improve on an already great game in the Bakken. Our operating teams did a tremendous job managing the growth in the past year, lately under challenging weather conditions. Their performance in 2013 was simply outstanding.

Now let's discuss well costs and operating efficiencies to provide yet another example. Our 5-year goal was to reduce well costs by an average of 3% to 5% per year, and again, we did A plus work in the first year.

Our 2013 goal was to reduce Bakken well costs from $9.2 million to $8.2 million by year end or 11%. We made so much progress in the first half, we lowered the goal to $8 million and we hit that target in the third quarter. So the first year, we have a 13% reduction in well costs.

Our goal for year end 2014 is $7.5 million per well for our standard design Bakken well or another 6% reduction.

Now we've also announced we'll be trying an alternative completion designs on about 20% of our Bakken wells this year, so their costs are likely to be higher.

The other key exploration achievement I'd like to highlight involves SCOOP. We only introduced a new play at our 2012 Investor Day, just 17 months ago. We told you the goals for 2013 would be to continue expanding our leasehold position while increasing our understanding of SCOOP's geology. We made tremendous progress last year.

As Harold noted, we increased our leasehold position significantly. Our key emphasis in SCOOP for the next couple of years will be delineation and appraisal of our leasehold position.

Just over half of our operator rigs are drilling extended laterals, an important step in improving already solid returns. We're also planning to do spacing tests and maybe wandered a couple density pilots later this year to prepare us to accelerate into development mode in future years.

Fourth quarter 2000 in production in SCOOP was more than triple production in the final quarter in 2012, which really tells a story. Although we're early in the learning curve in SCOOP, we plan to reduce well costs there as well. Our year end 2014 target is a blended average of $8.7 million for a 1-mile lateral well, including wells in both the condensate and oil fairways.

This short lateral well cost target compares with a fourth quarter 2013 average of $9.1 million for a typical exploration well in SCOOP. This is a little higher than we discussed early last year because we have increased the number of stages in our standard completion design.

Our year-end target for extended laterals is $13.5 million per well, and when we eventually transition to development drilling, we'll have a greater opportunity to reduce well cost.

Before handling the call over to John, let me emphasize that 2012 was a watershed year for Continental Resources as we grew the management and technical teams in preparation to be a significantly larger operator and producer by the end of 2017.

By the operating and financial numbers, it was a great execution year, it gives us even more confidence in achieving our 5-year goal.

Behind the numbers, we're also putting a lot of effort recruiting and integrating new people and skill sets in the Continental's organization, but at the same time, working hard to preserve the key traits that made this company so successful in the past 47 years, its innovation and entrepreneurial spirit, always alert for the next opportunity.

The love of exploration with prudent risk-taking, integrity, hard work and striving to be among the best wherever we work.

We are absolutely determined to preserve these values as we become a larger, more complex company, growing towards the achievement of our 5-year goal.

With that, I'll just turn the call over to John.

John D. Hart

Thanks, Rick. I'd like to look this morning at some of our other performance and financial metrics, especially as they relate to our 2013 guidance.

We committed to achieve and effortly revise production goal of 38% to 40% growth with a CapEx budget of $3.6 billion, and we were very disciplined with our spending throughout the year. The final number was 39% production growth and $3.57 billion in non-acquisition CapEx, which was $30 million under budget.

The key element in achieving this goal was -- it was improved operating efficiency. Rick noted the decreased well costs in our year end 2014 targets. Lower well costs continue to be an essential element in our overall capital and operating efficiency efforts.

We had similar results with operating expenses. Our revised goal for production expenses was a range of $5.60 to $6 per Boe of production, and we came in at the bottom end of the range, $5.69 per Boe for the year. We were a bit higher than this for the fourth quarter, but that simply reflected the deferred production volumes and temporary inefficiencies associated with weather.

Our target for cash G&A expense was $2 to $2.50 and we again came in at the low end of the range at $2.07 per Boe. Non-cash equity compensation was right on target at $0.80 per Boe.

Finally, DD&A was projected to be in the range of $18.50 to $19.50 per Boe, a positive reduction from the original guidance of $19 to $21.

For full year 2013, we achieved actual results of $19.47. The fourth quarter result was slightly higher due to the mix of wells completed and higher DD&A rates as we've focused on delineating the extent of the play, as well as testing the upper Bakken shale in multiple locations.

While some of the upper Bakken shale tests were promising initially, their decline rates overall were steeper than normal for the play.

We expect several related factors to reduce DD&A in 2014. First, the completion and production of our Tangsrud, Rollefstad and Wahpeton density projects in the first and second quarters.

Additionally, development drilling in the Antelope part of the play and further exploratory drilling in [indiscernible] . The average oil differential for 2013 came in at $8.23 per barrel, based on year end volatility in prices and spreads in the fourth quarter. This was lower than 2012, but slightly over the guidance range of $6 to $8 per barrel for 2013. Volatility will be a continuing challenge. Our guidance for 2014 is an oil differential range of $8 to $11 per barrel.

On the other hand, our natural gas differential was a premium with $1.59 per Mcf for 2013, $0.09 above the top end of our guidance range of $1 to $1.50, reflecting the richness of the gas we produce.

In terms of 2014, we reiterated guidance in yesterday's press release. We remain confident of hitting the 26% to 32% production growth target despite winter weather challenges in early January. We continue to roll in new hedge positions to support the stability of our drilling program and production growth.

We continue to work the balance, our derivative positions with our physical deliveries of oil as much as possible. We believe our utilization of financial hedges is a prudent measure, providing stability and operational flexibility for executing on our growth and capital plans.

Please refer to our 10-K filed this morning for a summary of our positions at year end. Next, let me add some color to Harold's point about our ability to source capital efficiently to support our growth strategy. One objective from the finance side of the business has been to reduce borrowing costs and expand our capital options, taking advantage of the flexibility inherent to Continental's strong balance sheet.

Clearly, our track record of exceptional operating performance is critical to this. We believe this record was an important factor in S&P and Moody's upgrading Continental to investment grade status in 2013, which obviously indicates we're on the right track in terms of disciplined growth.

Continental possesses long life, high-quality assets that support significant growth for years to come, attaining investment grade, not only a test of the quality of our assets, but it would also enable us to finance growth with greater certainty and to access broader markets.

We've also put in a great deal of effort in areas that are difficult for investors to depreciate, because they are behind the scenes. We've made significant strides in the past 18 months to cost effectively build the internal infrastructure we will need at the year end 2017 when Continental is 3x the size it was at the end of 2012.

This type of preparation is taking place throughout the Continental organization and gives us increased confidence that we will hit our 5-year growth goals.

We want to be sure and thank our teams for their efforts and commitments to our shared goals.

In summary, 2013 was a significant year in the Continental growth story. We have dramatically changed the company's profile in the last several years, transitioning from a small, independent oil company focused on the emerging Bakken play, to one of America's larger independents with strong operating footprints in 2 leading resource plays.

2014 is shaping up to be another year of strong growth in production, proved reserves and cash flow, underpinned by a strong balance sheet.

With that, I'd like to turn the call back over to our moderator, for the question-and-answer period. Thank you.

Question-and-Answer Session


[Operator Instructions] And our first question comes from Doug Leggate with Bank of America.

John Kilgallon

Vanessa, let's go to the next one. We'll see if Doug can get back in the queue.


We now have a question from Leo Mariani with RBC Capital Markets.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Guys, can you speak to kind of current SCOOP EURs? It looks like your production there has kind of outperformed versus your curves you had out there. Just wanted to see whether those were kind of a year end '13 the reserve report?

Richard E. Muncrief

Yes, Leo, it's Rick Muncrief. In the gas cost, you're looking about 1.2 million barrel equivalent, and then in the oil fairway, you're looking at about 650 MBoe.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

I guess, are those all on kind of short lateral wells, I'm guessing?

Richard E. Muncrief

That's correct. That's -- those are all assuming the 1-mile laterals.

Winston Frederick Bott

Leo, just to follow-up on that. We're -- as you guys, you've seen it from our release, we're drilling a lot, a higher percentage of these cross-unit wells. So it's going to later in the year before we actually come out with EURs for cross-unit wells.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

All right. I guess, just looking at the Bakken, obviously, you guys talked about weather impact. Is it possible for you guys to kind of quantify what you saw in the fourth quarter in terms of kind of what your lost? And it sounds like maybe you didn't get as many wells online in the Bakken in the fourth quarter. Could you -- do you have that number for us as well in terms of net wells completed?

Richard E. Muncrief

Yes, Leo. That number would be approximately 5,000 barrels a day equivalent for the quarterly average.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. And I guess just the number of wells you guys brought on in the fourth quarter on a net basis in the Bakken, do you guys have that?

Winston Frederick Bott

We bought on 37 net, 163 gross wells, IP, 1,800 barrels of oil equivalent per day, for the total North Dakota. Montana, 14 net, 17 gross, 600 barrels of oil equivalent per day, average IP.


And our next question comes from Drew Venker with Morgan Stanley.

Andrew Venker - Morgan Stanley, Research Division

In the Bakken, can you talk about what you've seen so far as you experiment with different completions?

Richard E. Muncrief

We're still early. We have tried several things. First off, we've tried several hybrid jobs, that's where you start with more of slick water type design and then transition to a linear gel onto a cross-linked gel and increase your profit concentration. We've seen a scattering of results on that. We're encouraged by that. We've also pumped a handful of slick water jobs. The results we've seen thus far are once again somewhat mixed, and we see some increased productivity certainly, probably, more so in the Middle Bakken than we do in the Three Forks thus far. But I'd also warned that we just have a handful of results, and there'll be more we'll talk about later on. And then the last thing that we have done is we've increased proppant. And one of the proppant projects you'll hear about in the near future is the Rollefstad, and that's one that where we have been [indiscernible] our stimulation designed by more proppant per stage on all those wells. And so, still has results and we will talk about later in the year. But that's we're at. As we've announced earlier, we're going to allocate about 20% of our capital program to try something different in our base design and we're off to a great start on that. So the acceleration of that will hopefully allow us to really hone in on the water of ultimate design needs to be.

Andrew Venker - Morgan Stanley, Research Division

Okay, that's helpful. And then in the SCOOP, can you compare the recent results to your expectations? I guess it would be helpful in particular if you could talk about how the 2-mile laterals compared to the single mile lateral results.

Richard E. Muncrief

Well, what we've seen thus far as that we've talked about is from a total comparison, you're looking at about a 50% increase on the CapEx and we're seeing 2 -- to slightly over 2x the productivity from a production rate and reserves. So we're extremely happy with the results we've seen thus far, and we think that's absolutely the way to develop this field over the long haul.


We now have a question from Doug Leggate with Bank of America.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Guys, if I can go back to the SCOOP real quick. So one of your competitors, obviously the Newfield, does come out with another upgrade. To their type curve it looks like yours is about, I guess, a couple years old now. Are we going to see you guys update your EURs on a per well basis? And how should we think about what the SCOOP looks like in a go-forward basis relative to the 2012 Analyst Day?

Richard E. Muncrief

Yes, Doug. It's Rick Muncrief gain. We will be updating our type curves. And as Harold mentioned, the Analyst Day that we're going to have in September, we think that you're going to really be quite pleased with everything you'll see there. But what we have now is we have a handful of wells with the extended laterals, some of those are just over 6,000 feet and we have some others that are 9,200 feet. And so we've got a smattering of different lengths of laterals. What we see, a very strong correlation on, is the lateral foot, the recovery per lateral foot is pretty predictive. And so from that, we think that we'll be able to update our type curves, I think you're going to like what you see.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Oh, okay. I guess we'll wait a couple of months about that. While I have you down, I wonder if I could ask you the same question about the Bakken. We haven't really heard you talk much about how the experimentation and completion design is, it might be impacting EURs and, ultimately, your development plans in the EON. I guess the Hawkinson is probably a good example of how this is going to play. Can you give us an idea as to whether or not you still think that you're -- I guess, you've stopped with 603 now for quite some time. Has the development area for Middle Bakken Three Forks as an average, how should we think about completion changes and ultimately, the upside or maybe the risk factor to 603? A little bit there.

Richard E. Muncrief

When we've stuck to the 603, I believe we laid that out for the first time in mid-2011. And so coming up on 3 years of that 603 model, and we really haven't changed it-- we haven't seen the need to change it. It seems like it's -- we're been able to deliver the programs that we have planned for. That being said, as we get into more of these multi-well unit developments, we're going to have a lot of factors. We're very bullish, obviously, on the Lower Three Forks as we've mentioned in our press release and what the results we're seeing for the Hawkinson. We're seeing the improved drilling cost, we're extremely excited about that. And then, the completion techniques that we're trying, we're going to get to an answer that we think is the way to ultimately develop the field. And so once again, I think you stay tuned. We're going to have enough information. It's real hard sometimes to be patient to wait on that information, but I think that's what is going to be so key for us, is that patience.

Harold G. Hamm

And one area too, Doug, that you might keep in mind, we're just now starting one of the development of the funded better areas of our whole Bakken acreage and that's Antelope, so what we're calling here Ears Back. So that's large area, and so that's going to also impact our model.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Guys, I don't want to be greedy with time here, but real quick, let me just follow-up. So under the links for the guidance you gave on production, is it fair to assume that when you laid our your original 5-year plan a couple of years ago, your first couple of years are running ahead of that guidance, but your completion seems to be improving your EURs, I guess, and the SCOOP are probably going to be improving. Is it fair to say there's probably some upside in production targets at this point?

Winston Frederick Bott

Well, I guess it all depends on price, doesn't it Doug? I mean, at the end of the day, we put out what we thought was a reasonable program for our 5-year plan. And we told you when we put that out that we were going to try to hit the ground running because we felt there was an opportunity for value capture and in the near-term, and to also prove some key things that we're going to move the needle in terms of total resource capacity in the Bakken. And just as a reminder, the 5-year plan really only required the first bench and the Middle Bakken to deliver the 5-year plan. And so everything that we're doing in SCOOP, everything we're doing in the lower benches is additive to the 5-year plan. But ultimately, the 5-year plan will become sort of secondary in terms of the full-field development, we start rolling into that. And so is there upside? There is upside but there's always risk on the downside too. So we're still pretty comfortable with that 5-year plan. We think getting ahead of it the first year gives us versatility in terms of making sure we can deliver it and now we've got optionality in the different play in SCOOP, and it's paid out for us in terms of the weather. The weather wasn't as impactful in SCOOP although we did have some impact, but it allows us to still hit that production target that we promised our investors.


Our next question comes from Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

Two questions. The first is on the rail side. Given that all that's gone on with regards to the potential for having to retrofit, refurbish or replace some of the tank cars. Can you just talk about your expectations and the conversations that you're having with your rail providers for the timing and the cost to producers of potential changes to the tank cars? And do you see a potential period of disruption even if it's temporary?

Jeffery B. Hume

This is Jeff Hume. And we have had conversations with all of the rail transporters that we're using both the rail road and the car manufacturers. They are currently going through design studies now of what -- where they will go with those cards, you saw the Burlington Northern Santa Fe and court orders in for over 5,000 cars with 2011 designs with some modifications. I think they'll come out with those quickly. From talking to the DOT, I think that we'll be more than likely brought in over a period of time to accommodate continued movement of the crude oil as we're bringing new car and upgrade it. There's quite a few of those new-styled cars already on the tracks. Most of the refiners that have added those cars that we deal with are using the new cars already. So we feel pretty comfortable here at Continental with the shipment of our crude oil continued. We applaud the scrutiny, I think they're barrel safety is key to continued use of rail for movement of oil is growing and working well. So we applaud the moves they're making. We think it will be managed in a way that will not interrupt our business and will be in good shape.

Harold G. Hamm

In addition to that, Brian. We have a lot of new pipes coming on this year and so we think the combination of that, make sure that we get our oil out in good shape.

Brian Singer - Goldman Sachs Group Inc., Research Division

Great. And then my second question is, in the press release, when you're talking about the Hawkinson results, I think you indicated that it validates your vision for full-field development of the Bakken. And I recognize that you've got more pilots less to fully validate your vision. But can you just talk more specifically about that vision when applied to spacing, number of zones and then the differentiation across your acreage?

Winston Frederick Bott

Well, it's real simple, Brian. In fact, I'm going to invite Jack to comment on, add to these comments. We think we've basically proven commercial productivity over a very large footprint at 3,800 square miles. We also recognize, as we've told you guys all along, that the rocks might be a little bit different in different areas. And as a rule, the deeper benches, second and third bench, come in pretty much in line with other wells in that area. We've talked about how the rock quality changes and the saturations changes as we go down into the interval, so I think we've talked about that numerous times. But the bottom line on this is there's commercial oil in the second and third benches, and we would not be prudent if we left it behind. So it's going to be a part of our full-field development, but that's going to be kind of an area-by-area sort of basis and we think the economics and rate of return in some of those deeper wells compete with anything we've got. So you probably will see us based on an area basis. Don't know what the exact spacing will be. We've got, as you say, we've got 6 more pilots to get under our belt and then we need production history from those to see how things change over 6 months and a year before we make those final decisions by area. But we think it's significantly added to the recoverable resource of the basin in the entire petroleum system. Jack, can you add to that?

Jack H. Stark

No, I think that really covered that well, Rick.

Brian Singer - Goldman Sachs Group Inc., Research Division

And do you view Hawkinson as a sweet spot within that -- within your acreage based on what you've seen?

Richard E. Muncrief

This area here, we do see above average production in the Hawkinson unit. But as far its character, as far as Three Forks is concerned or reservoirs, no, it's pretty much similar to what we see across the basin here as to the Lower Three Forks.

Winston Frederick Bott

I'll just add to that, Brian, that certainly because we've got the data now and we have another 6 months worth of production, it becomes a prime candidate to move into full-field development but so do the other 7 areas that we're doing these pilot programs on.

Richard E. Muncrief

Yes, and the key thing here is that this is only full-field development project that is actually -- this is the first full development in the field. We've got well bores in 4 zones, and we're seeing that all 4 zones are contributing and they're contributing at just great rates. I'm very encouraged of what we're seeing here and the results that we have in that third bench. To me, extremely encouraging here. It fits right in line with our expectations from what we know about the geology. As Rick mentioned, we do see variations in the rock as we go deeper. And so, I'd just say that this is a great start for us to get a clear vision of what it takes to fully develop this unit, or this field, and basically, leave no oil behind.


Our next question comes from Marshall Carver with Heikkinen Energy Advisors.

Marshall H. Carver - Heikkinen Energy Advisors, LLC

On the SCOOP play, you've got a good job of building the acreage position over the last, probably, several quarters. Have the recent acreage adds been in the sort of original de-risk footprint or they've been more in the expanding part of the play to the South? And what percentage of your acreage would you say is now in the oil window versus the condensate window?

Steven K. Owen

Yes, this is Steve Owen. We have put together a very substantial position throughout the entire play. We really aren't well into providing any additional data or detail at this point as to our leasehold position. Suffice it to say, we're continuing the acquire and lease in all of the key areas throughout SCOOP.

Richard E. Muncrief

And with regards to just what is, what's in the oil window, condensate and gas, approximately, right now we'd say of, maybe, about 40% of the position is in the oil, 40% is in condensate and the rest in more of a gas area.

Winston Frederick Bott

But Marshall, in terms of the play -- and we kind of define the play and I think we're pretty comfortable that we've got a significant, a good portion in all the good parts of the play. So I think we're pretty happy where we are. We've got some good acreage.

Marshall H. Carver - Heikkinen Energy Advisors, LLC

Okay. And I guess a follow-up, how many of the 2014 Bakken wells will be lower bench Three Forks versus Three Forks 1 and Middle Bakken?

Jack H. Stark

I was going to say, right now, we're probably in that range of 030, 35 right now. We're probably be in these lower benches. It varies as the year goes on here as we adjust some of the program, but -- and will be adjusted on the results.

Marshall H. Carver - Heikkinen Energy Advisors, LLC

Okay. That will be 30 to 35 net wells?

Jack H. Stark


Richard E. Muncrief

Net or gross?

Marshall H. Carver - Heikkinen Energy Advisors, LLC

Will that be a net or gross?

Jack H. Stark

That will be a gross. Well count is about 24 net, I think is where we end up.


Our next question is from Noel Parks with Ladenburg Thalmann.

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

I want to start with more of a broad question about the Williston overall. And I've been hearing some producers talk about what the actual trajectory of the basin's production growth is going to be. I think that -- thinking was that there'd be a very steep rise to a peak production level maybe later in the decade. But I've heard some people say that, just as you mentioned, the infrastructure has caught up in the play. Sort of where do you see the peak? And is it possible that it might be sort of a more gradual peak with a longer plateau, instead of sort of us continuing at this sort of break-neck pace we've had for the basin?

Winston Frederick Bott

Well, I think our projection is the same as it was. Our projection was that we saw a rise after about 2 million barrels a day overall. And I think we're sticking with that. We've seen kind of leveling off and even a little drop, if you will, in rig count up there. North Dakota, we had locked 171 rigs, last time I looked at it. And we think that, that's because the HBP acreage, most of it's HBP-ed. Operators are going to slack down a little bit. Winter weather, of course, had some effect this year with people that had been up there too long. So I think it may be a little bit more gradual as we see proppants build out and things like that. But it's a very measured approach that's going on by operators up there. We've taken that approach. People are following our lead and we think it's the responsible thing to do.

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

Great. And I wanted to ask about in the pads after the Hawkinson, the Rollefstad, and the Wahpeton and the drilling. I remember with the Hawkinson, you had a faster-than-planned cycle time in the drilling and I wondered if you'd seen those same pace continue on with the newer pads, and just what that might look like going forward.

Richard E. Muncrief

Yes. We did see cycle times, really attractive cycle times on all 3 of the pads, and it's a little bit of a shame that we've got a little bit of the weather impact. We're not making excuses, getting out of those completed proton. But certainly, from a cost perspective, it's very impactful. And the reason it's impactful is when you really start looking at, as Rick and Jack and Harold all have alluded to, in the lower benches is -- you're seeing the ability to go in and harvest this oil at a very attractive, economic picture. For instance, we've looked at some of the Lower Three Forks and the TF3 on the Hawkinson. And even though 2 of the wells are still under the 603 model, as we suggested in our earnings release, we still have seen economics on those 3 wells that suggest 35% to 40% rate of returns, and that's very attractive to start looking at a $7.5-million well cost from a pad. And so we see the cycle times continuing, you see it really across the board. We don't talk much about our outside operated activity, but we see it with some other operators' well, which helps us because it drives those costs down. And the outside operated have purpose, sees as well. So I think what you're going to see is continued economic enhancements over the next 3 to 4 years without any doubt.


[Operator Instructions] Our next question comes from Leo Mariani with RBC Capital Markets.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Guys, I just have a follow-up regarding your oil price realizations. Just kind of looking at the fourth quarter of 2013, it looks like your oil price realizations were down, roughly $13.50 by my math here. And just kind of looking at some of the benchmark pricing, I'm seeing that Brent was down roughly $1 from 3Q to 4Q and LLS was down by $9 and WTI was down about $8.50. But I guess, your realization was kind of down more, I was just looking for maybe some color around that if you, guys, had any.

Jeffery B. Hume

Leo, this is Jeff Hume. Several things happened that put pressure on us in the fourth quarter, one was the widening refinery changing from sweet crude to Canadian bitumen, around 200,000 barrels a day of light sweet market went out of the pipeline delivered market. And so it's putting more pressure on the rail. The good news this quarter, we're opening up more pipeline spaces line and Bridgeline 9 opens up to the Great Lakes refinery sector putting more out there. We have the Keystone South working thus we're leaving cushing allowing more oil to flow down into the cushing area. And refineries are coming back on. We had some early turnarounds due to a couple of fires up in the Rocky, the Northern Great Plains region, and then up in Minnesota, so they did some early turnarounds. All of that hit together, and at the same time, Syncrude units were running at capacity in Canada. So there's a lot of oil showed up, and at the same time, we had some restrictions that occurred, most of them were unplanned, a couple of them were planned, and so a full shock in the system, but that's being taken care of. As Harold said, we have the Pony express pipeline that's going to be coming on, taking around 210,000 barrels a day out of the basin starting in the third quarter. Will give us more relief. And we're seeing an improved rail service up there. So opening more and more markets, and most of that is from unloading side of the rail, it's not loading at the basin, it's unloading at the refineries, we're seeing improved infrastructure built out there. So I think we'll see smoother, we're seeing the rail compete more with the local crude pricing. And so I think thing's are going to be picking for us and that's -- so we've put the guidance set that we have and we think we can hit that.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

That's great color. I guess, as with respect to that obviously you've got a bit of a range on your differentials in your guidance. I mean, obviously market conditions are hard to predict but all things being equal, would you expect to see improving realization as we get maybe later in the year as some of these pipes come on, and then maybe some further improvement potentially in '15?

Jeffery B. Hume

I do. I think the continued -- just looking out in front of us, I think we should be seeing continued improvement. We're working on several fronts as all the operators out there. One is the quality of our crude, that words are getting out that it's high quality in value. I think we'll start seeing improved competition for our crude at the other end of the line as we get more pipeline south that's going to lower cost and bring on competition, a little more competition for that crude. Transportation cost will eventually work down as you build out that infrastructure, so I agree.


Our next question comes from Andrew Coleman with Raymond James.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Just on the Hawkinson pad wells, and the subsequent ones, I guess, how much improvement have you all seen, I guess, in terms of start to finish times from site preparations to tying in the wells? And how should I extrapolate that, I guess, into my NAV model going forward?

Richard E. Muncrief

Good question, Andrew. What we have seen is we've seen in the Hawkinson, for instance, we saw about a 10% improvement over what we had modeled. The cycle time being from start to finish, and that was with some complex microseismic, we had a lot of things along the way that we did there that -- but so I think that what you can look at is site preparation is really not an issue. We've got that pretty well done ahead of time, and then we start looking at just actual cycle times on the big pads, big pads being greater than 8 wells per pad. We're looking at about a 20-day to 22-day average on those from spud to rig release to the next well. And then in some cases, and it depends on the pads, we can do some simultaneous operation. So we're doing everything we can to accelerate that for a couple of reasons and obviously, to bring out production on, but also to accelerate our understanding. So we can probably provide a little more color later on as we get into it. Some of these will be sites-specific.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Okay. And so then thinking about, I guess, you're going to get average as 22 rigs this year, so maybe another -- as Ears Back kind of gets there, and gets more data probably about the fall, maybe we'll have some view by then on the in terms how rig count might stabilize and start declining as you ratchet up the activity?

Richard E. Muncrief

Yes, that's correct. Right now, for instance in antelope, we're at 3 rigs today, we'll have a fourth rig probably within the next 4 to 5 weeks. A fifth rig in the second quarter. And hopefully, a sixth rig in the third quarter.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Okay. And do you anticipate -- as you test the 20% wells made bigger fracs, are there sort of science work that you would see any, I guess, leakage, in terms of time? The other way, as you change the ultimate completions style? Or anything you really get in that window?

Richard E. Muncrief

No, I think we can. If you look at some of the larger, especially the slick water fracs, it just takes a little more preplanning upfront, but we've got a team that's doing that. We're rolling it, right now, with 8 stimulation crews. And so we've got the operating capabilities to handle that plan effectively, source it. And so I don't think you're going to see much slippage on time. We will execute.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Okay, all right. And then last question I had, puds in the reserves report, I guess, were approaching 60% I think by year end. I guess how much higher can you see that going? And I guess, does that point you toward a minimum sort of well count to kind of stay up on that wave as you continue exploring the resource up in the Bakken?

Richard E. Muncrief

Well, if you look at the total puds, if you look at Continental across the company in the Bakken, we've got just over about one in the third or so puds producing that well, and SCOOP worth about 2 puds per producing well. And so we've got, in both of the plays, we've got obviously a lot of resource there that we can book in the future. But obviously, one of the things that comes into play is what you can get done in a 5-year period. We got -- and that's something that we'll, obviously, always be addressing. But I do think that what you're going to see is, with increased reserve, booking out of per well basis across our company, you're going to see continued growth, and I think it that we're going to be in really, really good shape to meet our 5-year plan.


And we have no further questions at this time. I would now turn the call over to Mr. Harold Hamm for closing remarks.

Harold G. Hamm

Thanks Vanessa. Again, I'd like to thank everybody for joining us today on this conference call.

Continental delivered another very strong year in 2013, and we look forward to record achievements again next year.

By the way, you may have noticed, 2 new titles in introduction today, and I'll address those. Along with a number of other promotions here in the company last week. We have a John Kilgallon to the leadership role in Investor Relations. Warren Henry takes on a new challenge as VP of Research and Policy. He'll remain heavily involved, of course, with IR but he will also support public relations, governmental affairs and executive group with research and proposals for addressing state and federal issues such as transportation, exports, regulation and others that impact Continental's growth strategy. It's just a great fit for Warren's background, and John has proven he's already detective range in IR. I know our investors have very strong relationships with both Warren and John, so please feel free to call either them with your questions. They'll continue working together closely. That completes our call today. Thanks again, and we look forward to speaking with you again in early May.


And thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to All other use is prohibited.


If you have any additional questions about our online transcripts, please contact us at: Thank you!