Continental Resources, Inc.

J. Warren Henry - Vice President-Investor Relations & Research Jack H.

Stark - President & Chief Operating Officer John D. Hart - Chief Financial Officer, Treasurer & SVP Harold G.

Hamm - Chairman & Chief Executive Officer Gary E. Gould - Senior Vice President, Operations Glen A.

Brown - Senior Vice President, Exploration Blu Hulsey - Vice President-Government & Regulatory Affairs

Doug Leggate - Bank of America Merrill Lynch Leo Mariani - RBC Capital Markets LLC Brian A. Singer - Goldman Sachs & Co.

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

(Broker) Pearce Wheless Hammond - Simmons & Company International Subash Chandra - Guggenheim Securities LLC Brian Michael Corales - Scotia Howard Weil Phil J. Jungwirth - BMO Capital Markets (United States) Paul Grigel - Macquarie Capital (USA), Inc.

Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.

Harry Mateer - Barclays Capital, Inc. Marshall H.

Carver - Heikkinen Energy Advisors

Thank you, Catherine. I'd like to welcome everyone to today's call.

Joining us today with prepared remarks are Harold Hamm, Chairman and Chief Executive Officer; Jack Stark, President and Chief Operating Officer; and John Hart, Senior Vice President, Chief Financial Officer and Treasurer. Also on the call this morning and available for Q&A will be Jeff Hume, Vice Chairman of Strategic Initiatives; Jose Bayardo, Senior Vice President of Resource and Business Development; Gary Gould, Senior Vice President of Operations; Glen Brown, Senior Vice President, Exploration; and Steve Owen, Senior Vice President of Land.

Today's call will contain forward-looking statements that address projections, assumptions and guidance. Actual results may differ materially from those contained in our forward-looking statements.

Please refer to the company's filings with the Securities and Exchange Commission for additional information concerning these statements and risks. In addition, Continental does not undertake any obligation to update our forward-looking statements made on this call.

Also on the call, we will refer to certain non-GAAP financial measures. For a reconciliation of non-GAAP measures to generally accepted accounting principles, please refer to the updated second quarter and first half summary presentation that was posted on our website at www.clr.com yesterday evening.

To begin this morning, I'll turn the call over to Jack Stark for his comments on the second quarter and our current outlook. Jack?

Thank you, Warren, and good morning, everyone. We appreciate you being on the call with us here today.

I am very pleased to report that Continental delivered another quarter of excellent results, especially with the backdrop of prevailing low commodity prices. Our team stayed right on track with our plan to align CapEx with cash flow, lowered costs across the board, build efficiencies and to maximize the return on every dollar spent.

As a result, our production for the quarter hit record levels and our cash costs such as G&A and LOE came in significantly below guidance. So based on our strong results year-to-date, we have increased our production guidance for 2015 and lowered our projected cash costs for the year with no adjustments to CapEx.

In fact, our CapEx is running about $85 million below budget at midyear and in our current pace CapEx would run as much as a $150 million below our $2.7 billion budget by year-end. Bottom line, more production at a lower cost.

John will provide more details on our updated guidance here in just a few minutes. In addition to these outstanding results, we are officially adding STACK to Continental's portfolio of world-class assets.

As announced, our first STACK well flowed at an impressive rate of 2,076 barrels of oil equivalent per day and it indicates that STACK constitutes a significant new resource play underlying our 136,400 net acres in Central – in the STACK play. Needless to say, we are pleased with the results, and I will discuss STACK in more detail in a few minutes.

Speaking for the management team, we can't thank our employees enough for embracing the market changes and delivering excellent results in the first half of 2015. Their dedication and ingenuity has laid the foundation for Continental to operate successfully in today's environment.

So let's look at some of the results for the quarter. For starters, our production averaged a record 226,000 barrels of oil equivalent per day for the quarter, up 10% from Q1 and 35% over Q2 2014 and current production is approximately 230,000 barrels of oil equivalent per day, quite impressive considering we've reduced our rig count by 50% from fourth quarter 2014.

Those volume growth was driven primarily by four things: one, high grading our Bakken drilling program; two, improved Bakken performance from enhanced completions; three, continued impressive results from our SCOOP Woodford and Springer completions; and four, momentum coming out of 2014. Looking to the second half of 2015, we expect production will decline slightly in the third quarter and level off in the fourth quarter, reflecting a lower level spend that we have planned.

Our year-end 2015 exit rate is projected to be 210,000 barrels to 215,000 barrels of oil per day and there may be some upside to this number as efficiencies continued to build. We currently have 25 operated rigs running with 10 in the Bakken, 10 in SCOOP, four in Northwest Cana, and one in STACK.

We plan to keep approximately 25 rigs drilling throughout year end, but are prepared to reduce the rig count in the Bakken by 20% should today's low prices persist. On the capital side, our drilling and completion costs have decreased approximately 20% at midyear compared to year-end 2014.

Most of the cost reductions are coming from the service sector and are weighted more heavily towards the completion side. Our goal is to have an additional 5% to perhaps 10% reduction in costs during the second half of the year from a combination of operational efficiencies and further reductions through improved drilling and completion methods.

In terms of operational efficiencies, we're seeing improvements in all aspects of our business. On the drilling side, the Bakken team has reduced drilling times from an average of 17.6 days in the first quarter of this year to 16.6 days in the second quarter, a 6% reduction quarter-over-quarter and they continued to push the technical limit.

In the first half of 2015, they've drilled 12 wells from spud to TD in less than 14 days with one well reaching TD in only 12.6 days. Seven of these sub 14-day wells were drilled in the second quarter.

So the key here is that the results are repeatable and represent a step-change that will pay dividends for years to come as we develop our Bakken assets. In SCOOP, it's a little harder to measure the operational efficiency gains as we're still delineating the play at a variety of depths and experimenting with various drilling and completion techniques, but we see efficiency building and based on experience we believe gains in the range of 20% to 30% are possible as the play matures over the next several years.

As an example, our drilling team drilled this first well using short set intermediate pipe in the Woodford saving approximately $500,000 on a well. Another Woodford well drilled during the quarter, they saved approximately $1 million by eliminating the intermediate string of pipe altogether.

We believe this approach could be applied to approximately 30% of our SCOOP acreage. Now, let's move to production performance.

In the Bakken, we are seeing significant uplift in the well performance from high grading to the core and utilizing enhanced slickwater and hybrid completions. By doing so, we are targeting an average of 800,000 barrels of oil equivalent EUR per well this year compared to an average EUR of 550,000 barrels of oil equivalent for 2014 when we're drilling and testing completions of a broad area outside of core.

That is a 45% increase in EUR, which along with our completed well cost reductions, essentially cuts our 2015 Bakken finding and development costs in half compared to 2014. Looking at it another way, we estimate that for every dollar we spend on our Bakken wells in 2015, we are getting approximately 80% more reserves than we did in 2014, and we estimated that we have approximately 10 years of drilling inventory at 775,000 barrels of oil equivalent based on drilling program averaging 15 rigs.

Our slickwater and hybrid completions continued to deliver initial 90-day production rate uplifts of 50% and 40% respectively, compared with offset legacy completions in Williams and McKenzie County. We are also projecting uplifts of 25% to 45% in our EUR for these enhanced completions.

Our SCOOP production continues to grow and now represents 28% of the company's total production in the second quarter, up from 24% of company production in the first quarter of 2015. Almost a third of SCOOP second quarter production was crude oil.

We continued to de-risk our SCOOP acreage with step-out and pilot drilling tests and results from the drilling Woodford and Springer wells during the quarter were really quite strong. In the Woodford, we completed 15 net 50 gross operated and non-operated wells during the quarter.

The average 24-hour test rate for these wells was 1,539 barrels of oil equivalent per day. During the quarter, we also completed our second pilot density test in the Woodford condensate window called the Honeycutt.

The Honeycutt in which Continental owns 50% working interest is a 10 well dual-zone density pilot located one mile east of the 10 well dual-zone Poteet density pilot announced last quarter. The Honeycutt density pilot consists of one legacy well and nine new wells.

The nine new wells in the Honeycutt pilot flowed at a combined peak rate of 93 million cubic feet of gas per day, and 9,058 barrels of oil per day or 24,603 barrels of oil equivalent per day. On a per well basis, the nine Honeycutt wells had an average IP of 2,734 barrels of oil equivalent per day, which is remarkably close to the average IP for the Poteet density pilot wells of 2,774 barrels of oil equivalent per day.

On the Honeycutt project, approximately 37% of the production was crude oil compared with 12% oil cut for the Poteet wells. This is consistent with expectations as the Honeycutt pilot was located closer to the oil window moving eastward into the play.

Both the Poteet and Honeycutt pilots were configured as dual level tests with five wells in both the upper and lower Woodford. Approximately, one-third of our 460,000 net acres of leasehold at SCOOP is prospective for dual-zone development like this where the Woodford is greater than 225 foot thick.

As an update, Poteet continued to perform very well and in line with expectations. The 10 new pilot – the 10 new Poteet wells have been producing for over 140 days and it produced 14 Bcf and 242,000 barrels of oil and they continue to produce at 80 million cubic feet of gas per day and 828 barrels of oil per day.

In the Springer, we completed three net and five gross operated and non-operated wells during the quarter. The average 24-hour test rate for these wells was 1,385 barrels of oil equivalent per day.

The Celesta 1-5-32XH in Stephens County was our second extended lateral well in the Springer and it had a maximum 24-hour test rate of 1,199 barrels of oil equivalent per day from the 7,119 foot lateral. In our Northwest Cana JDA, we had several outstanding completions during the second quarter as well.

The Jones Bay 1-7-6XH and Heckenberg 1-19-30XH had maximum IP rates of 12.5 million cubic feet of gas per day and 15.5 million cubic feet of gas per day respectively. The Akin 1-27-22XH had an IP of 9.9 million cubic feet of gas per day and a 60-day average of 8.4 million cubic feet of gas per day.

In total, during the second quarter, we completed 2.3 net five gross operated and non-operated wells in Northwest Cana with an average IP of more than 12 million cubic feet of gas per day. Now, before I conclude my comments, let's get back to the new resource play we are officially adding to our portfolio and that's STACK.

As announced, the Ludwig 1-22-15XH was completed, flowing 2,076 barrels of oil equivalent per day. The well has only been producing for six days now and is still cleaning up, but is a very strong well producing at 2,100 pounds flowing casing pressure.

Approximately, 76% of the production was 44-degree gravity oil, the rest was 1,460 Btu gas. The well targeted the Meramec and it was completed with 40 stages in a 9,711 foot lateral.

It took 38 days to drill from spud to TD at an estimated cost of about $10.9 million. Continental controls 136,400 net acres in STACK and approximately 60% of this acreage is already held by production.

The remaining acreage that we already held in inventory and it came to us at no cost. The Ludwig is located on the east side of our acreage block within the over-pressured window and in fact 95% of our acreage is located within the over-pressured window where we believe well performance will be enhanced.

Underlying our acreage the STACK petroleum system, which we currently defined as the base Woodford to top Meramec is approximately 700 feet to 1,200 feet thick and is found at depths of 9,000 feet to 17,000 feet. And of course, it's too early to estimate reserves for the Ludwig but based on industry-wide results, we anticipate the economics from STACK will compare favorably with our Bakken and SCOOP assets.

We're very encouraged from the Ludwig results and have already drilled the second well, the Marks 1-9-4XH and a third well is drilling. We are adding a second rig to STACK later this quarter as well and expect to have a total of eight wells to nine wells spud by year-end 2015.

So in summary, Continental's performance in the first half of 2015 shows the strength and scalability of our assets, the flexibility of our operations and the capital discipline employed. We look forward to reporting continued progress along the same lines through the remainder of the year.

With that, I'll turn it over to John to discuss updated guidance and financial results.

Thank you, Jack. Good morning, everyone.

We're pleased to report our results today. Revenue for the second quarter was $796 million, an increase of 27% over the first quarter.

EBITDAX was $647 million, an increase of 47% over the first quarter. And net income was a positive $403,000.

Adjusted to exclude impairments, non-cash gains and losses on derivatives and gains and losses on asset sales, net income was $48.5 million or $0.13 per diluted share. Although the net income isn't large in an absolute sense, it is significant in demonstrating we can be profitable in a lower commodity price environment.

Our results were driven by strong production growth, as Jack discussed, and exceptional operating cost results. These reflect the lean, focused nature of our company, combined with the quality of our assets.

We've been able to generate production growth while improving our cash cost and lowering our unit rate. For instance, look at G&A excluding equity compensation.

In 2011, our G&A per Boe was $2.36. It was $2.06 last year and for the second quarter it was an impressive $1.34 per Boe.

Our 1,180 employees generate outsized results. Production expense is a similar trend, improving from $6.13 per Boe in 2011 to $5.58 in 2014 and $4.39 per Boe in the second quarter of 2015.

As we develop our core areas and gain greater density, our efficiencies continue to improve. Our results reflect long-term sustainable trends that should continue to enhance our results in the future.

Total cash costs, including interest, was lower at $12.43 per Boe in the second quarter or 9% better than Q1 and 30% better than 2014 as a whole. These measures not only distinguish Continental within our industry, they continue to aid us in terms of our global competitiveness.

As we noted, we are forecasting production to level off in the back half of the year, with reduced quarterly CapEx. As Jack mentioned, we expect our exit rate to be around 210,000 Boe to 215,000 Boe per day.

Per unit cost may increase a bit from Q2 levels. However, we anticipate they will continue to be exceptional and well inside our prior guidance.

Accordingly, we updated our 2015 guidance in a significantly positive manner last night. The overriding theme of this update is stronger production for fewer capital dollars spend with significantly improving cash cost per Boe.

These operating and financial metrics will continue to be our focus for the remainder of 2015 and prospectively. Changes in 2015 guidance include: an increase in our expected production to a range of 19% to 23% versus the prior growth rate of 16% to 20%, reflecting the strong results our wells are generating; the production expense guidance decreased to $4.75 to $5.25 per Boe in comparison to the prior range of $5.50 to $6; G&A decreased to a range of $1.75 to $2.25 per Boe from the previous range of $2 to $2.50; finally, equity compensation improved to the range of $0.7 to $0.8 per Boe, down from the prior range of $0.75 to $0.95.

A full look at the 2015 guidance can be found in our investor presentation posted on the website and at the end of yesterday's earnings release. First quarter oil and gas differentials were within guidance at a negative $8.18 per barrel for oil and $0.33 per Mcf for natural gas.

The strong Q1 to Q2 improvement of 18% in oil differentials reflects a more competitive market environment with the commencement of the Pony Express Pipeline combined with ample railroad takeaway capacity. Approximately 70% of our Bakken production is now delivered to market via pipeline, contrasting with where we were a year ago.

Although differentials can be volatile quarter-to-quarter, we expect to see continued multi-year improvement as new pipeline capacity creates more competition for the available supply. Additionally, Harold will discuss our views on lifting the ban on the U.S.

crude oil exports. I note that we believe doing so would positively benefit WTI relative to Brent.

On the financial front, we continue to have ample liquidity and no near-term maturities. Our capital plans for the second half of 2015 do not entail accessing the capital markets.

At the end of 2Q, we had $25 million of cash on hand and we currently have $1.3 billion available capacity under our credit facility. We remain committed to maintaining our investment grade rating.

Capital expenditures for the second quarter were $586 million, which was $27 million below our internal budget for the quarter, resulting in $85 million below budget through the first half of the year. Though we are not formally revising our 2015 capital budget, at the current spending rate we are trending about $150 million below our 2015 CapEx budget of $2.7 billion for the entire year.

Given the current market, we would not deploy this incremental capital, but instead expect to be under-budget for the full year. Apart from this, we could reduce our capital spend even further during the back half of the year to better align CapEx with cash flow at today's lower commodity prices.

So, let's specifically discuss cash flow neutrality and where we stand. As previously noted, at $60 WTI we would be neutral in the back half of 2015.

At $50 WTI, we would outspend cash flow by about $150 million to $200 million during the back half of the year. And this is without the benefit of additional cost reductions.

However, as we will discuss, we expect continued cost improvement, which should benefit these numbers further. Before the most recent decline in commodity prices, we were in essence at neutrality.

As an example, for the month of June, we were cash flow positive with an average WTI price of $59.83, reflecting how quickly we have been aligning with cash flow. As another reference point, you may note in our 10-Q that our July month end revolver balance was flat with June.

While pleased with our progress to date, we're managing the company to achieve our financial and operational objectives in any commodity environment. We have alternatives to the current budget and we'll further reduce capital spend if necessary to better align with cash flow.

Now, let's discuss 2016. Previously, we stated that maintenance capital to hold production flat in 2016 was estimated to be $2 billion to $2.2 billion.

Today, based on lower cost and increased efficiencies, we now estimated lower maintenance capital range of $1.8 billion to $2 billion to hold us flat at our expected exit rate of approximately 210,000 Boe to 215,000 Boe per day. We have also noted in the past various growth scenarios.

Today, we estimate that for approximately $2.5 billion in 2016, we could grow in the mid to upper single digits from our 2015 exit rate. This is stronger production and lower CapEx than we announced last quarter when we referenced flat CapEx of $2.7 billion, so a nice improvement.

As another reference point, 2016 maintenance capital of $1.8 billion to $2 billion would enable us to be cash flow positive at $60 WTI and at $50 would result in an outspend of $300 million to $400 million. These estimates are based on a 25% cost savings relative to 2014 or the low end of our year-end 2015 target.

So we feel that we may be conservative in these estimates. Our goal is to significantly reduce these amounts through incremental cost savings and efficiencies or by reducing activity further.

As a reference point, every 5% in cost savings will save about $110 million in CapEx. These estimates are strong indicators of the quality of our assets and Continental's operating excellence.

As indicated in prior calls, we plan to announce formal 2016 guidance late this year. In summary, we are committed to a disciplined approach in managing our business and preserving our financial flexibility.

We do not believe the current price environment is sustainable and we will remain patient awaiting better commodity prices before deploying additional capital. As second quarter 2015 demonstrates, our efficiency and cost improvements are allowing us to do more with less capital.

We are creating competitive advantages that will be strong value catalyst for the future. Now, I'd like to turn the call over to Harold.

Thank you, John. The quality and competence of Continental people have never been more apparent and strategically impactful than they are today in mid 2015.

The results have been truly exceptional and I'm enormously proud of what we have accomplished this quarter. We have demonstrated capital discipline while we continue to increase production and reduce costs.

We have literally reset the bar in every key component of our business, an increase in our 2015 production, decrease in production expense per Boe, decrease in G&A per Boe, improved equity compensation per Boe, least cash flow neutrality for June 2015, we plan to be cash flow neutral in the second half of 2015. As Jack had described so well, we saw tremendous second quarter accomplishments in the STACK, SCOOP, Northwest Cana and the Bakken results versus capital costs.

Those accomplishments reflect increased communication and team work between Oklahoma City office and the field, focus in accountability throughout the organization and fierce determination to get better every day in everything we do here at Continental. Oil supply and demand will rebalance.

In terms of the supply rebalancing coming out as paradigm shift, we're watching several key factors. The U.S.

oil production growth curve is turning over, so the primary source of world supply growth will not be there in the last half of 2015 nor 2016, given all the rigs the industry has laid down. Secondly, we're not seeing enough supply growth worldwide to offset the natural declines in production.

OPEC has announced plan to reduce production beginning in September and we think that maybe the first of many. And finally, we're seeing meaningful world demand growth led by lower oil prices, which will speed rebalancing.

This energy paradigm shift will have profound long-term consequence worldwide, starting with the U.S. crude exports ban being lifted so America can finally compete freely in world energy markets and receive the full value for oil and contrast with Brent selling at a 10% premium today and 20% for much of the last four years.

U.S. oil exports simply make too much sense economically, especially as this administration moves to lift restrictions on Iranian oil exports.

I'm personally very committed to this issue having testified numerous times at both Senate and Congressional hearings and having met with hundreds of Congressmen, representatives and staff members over the past year in my role as Chairman of the Domestic Energy Producers Alliance. This educational process has been arduous, but necessary to lift this 40-year-old Nixon-era ban.

World events including OPEC factions and recently proposed Iranian nuclear agreement have written an ideal script. Now momentum is at an all-time high and I believe we are on track to see the ban lifted early this fall.

Another historic consequence is the recognition that the U.S. energy renaissance is a multi-decade reality, in which Continental will be a large participant going forward.

America is once again an energy superpower, no longer depending on unstable regimes, overseas for our primary energy supplies. Just like we did in the 1940s, 1950s and 1960s, we have the resource and technology to be the world leader in energy production.

Along with the economics and jobs, this has huge implication geopolitically especially in terms of supporting our allies in Europe and other parts of world. Finally and personally, this brings me to my final point regarding paradigm shift.

I'm enormously proud of the role played by Continental Resources later in the U.S. energy renaissance and have the dominant leasehold we've acquired in heart of three of the most prolific plays in America, the STACK and the SCOOP and the Bakken.

We've assembled an unmatched asset portfolio, a powerful growth platform for decades to come for this company. The key point today is Continental is better positioned than ever for future growth and to play a leading role in the next 20 years of the U.S.

energy development. We have the assets, balance sheet, people, ability to execute, and discipline to grow, and prosper in any reasonable price environment.

As these historic events continue to play out, we'll make sure the company remains sound financially to remain viable and ready for increased growth at the proper time. And one final point of interest, at Continental, we have always been exploration is first.

Accompanying that fact, we've taken advantage of low price environments like this to find our best resource play starting with Cedar Hills in the mid 1990s, the Bakken in 2002 and in SCOOP in 2008, 2009. Now, we added STACK to that list, a play that we believe will compete with any of them with the added luxury that is 60% HBP for Continental.

This acreage position is also ideally located in the pressure cell of this petroleum system, within our best plays and adverse markets, then as the market turn around we're ready to fully develop them with our own gas prices. That's the history of Continental.

We are positioned well to do it again. Thank you with that.

I would like to turn the call over to our operator for the Q&A part of the call. Thank you.

Thank you. Good morning, everybody, or good afternoon I guess it is now.

But I wonder if I could hit two separate issues, fellas, please. The first one is financial and the second one is on obviously the terrific operating results you announced in several of the plays.

So I guess, John, dealing first of all with the balance sheet issues. I wonder if you could just address at least what we hear is one of the primary reasons for Continental's share price weakness recently which is the perception that there will be a need for equity at some point to achieve your financial objectives and a maintenance capital scenario, could you address that?

And in doing so, maybe talk about what – some of the options you are – you see as a way as if you needed to basically maintain those investment grade credit metrics?

Okay. I think that's probably a narrow perception with the depth and quality of the assets the company has.

We have a lot of optionality in how we approach it. One, if you look to metrics, debt to EBITDA is obviously price-driven, debt to flowing barrel has actually improved and you see some strength in terms of cost in a lot of the other measures, so you're seeing improvement there and greater efficiencies.

As you look beyond that with those optionalities, we've looked – if you look to the past of what we've done, we have utilized a variety of capital markets at different times, all forms of those. We've also used a strategic asset monetizations and joint ventures to fund our operations and with the portfolio that we have, we have some tremendously valuable pieces that could provide cash in those type environments without going to the markets.

Additionally, in terms of our metrics and the point that it is price driven, if you look at it from the terms of a $60 price environment, or even subsequently a $70 price environment, you see a rapid and dramatic transformation of those metrics. So, yes, at $45, it looks a little higher but as you look back just four weeks ago when we were at $60, you were seeing a lot more strength in that.

I would also say I think our metrics are probably better than what many projected and internally as we look out, we see them better than what a lot of people are projecting. So we've got a lot of optionality.

We will preserve the financial strength. But the first thing we do is we adjust our level of spend, which we've done.

We bring down the level of activity. We get in line with cash flow, prices continue to dip and we will continue to work in that vein and we stopped utilizing debt and we're well-positioned for the future with ample liquidity.

And then as it recovers, we look to those other options to accelerate that development and growth in those recovered markets.

I think, Doug, it's a good question. I think a lot of people didn't expect us to get to cash flow neutrality as quickly as we did.

So they had a little different deal. And so many companies went out there and diluted their shareholders by issuing equity early in this downturn and maybe that's why they expect us to, but certainly we have optionality that didn't require to do so.

I appreciate the answers, fellas. And, Harold, thank you for weighing in there.

My follow up is probably for Jack. And it's really a question about variability and I'm sure I'm going to leave plenty time, so I'll let people to get on here.

But if you look at Poteet versus Honeycutt, if you look at the variability in the Springer, what's the reason you think for two areas very close together the – I guess the well, the pilot test but with very different oil cuts in the Poteet case and in the case of Springer some fairly large variability in the IP rates. And I'll leave you there for somebody else to jump on about the STACK.

Thanks.

Hi, Doug. Yeah, this is Jack.

As far as the higher oil cut in the Honeycutt well, I mean that was exactly what we are expecting. This is a transitional play where you transitioned from oil to gas over a distance and this is – these wells are really – you can see the Honeycutt is entering that transition to a more oily area.

And so it's mile east of the Poteet and so – and you do start seeing a transition in that short of a distance.

On the Springer, Jack?

And as far as the Springer – variability in the Springer, really Springer results to me, I don't see a lot of variability in it. We're really pleased with the outcomes.

I mean these two wells we announced are above the type curve in their early time performance and what I'm saying, if anything, of variability would just be related to reservoir thickness and that's about it.

Terrific. I'll let someone else jump on.

Thanks, guys.

Thank you.

Hey, guys. Just wanted to ask a question here around the production growth cadence in the second half of the year, you guys talked that your third quarter production will be down a little bit and I think you guys said in your prepared comments that your fourth quarter would start to recover to flat a little bit.

I was just trying to reconcile that with the comment that current production was 230,000 barrels a day, which is up a little bit from the second quarter average. I guess, are you starting to see declines kick in later in August and September, just wanted to make sure I understood that.

Yeah, this is Gary Gould. I'll comment on that.

As we rolled into the beginning of this year, we had a lot of inventory and we had a lot more rigs running. And so in the first half of the year, we've completed a lot more wells on what we see forecast for the second half of the year.

And so that's really the driver. When we look at actual production performance per well, we're seeing very good results, whether it be from the north or from the south.

Okay. That's helpful.

And I guess in terms of looking at where we're going to see the production start to decline here, is that going to be more so from the Bakken versus the SCOOP? I mean, your rate of growth in SCOOP has been a fair bit higher over the last handful of quarters versus the Bakken.

Just trying to get a sense of how those two individual assets may change here later in the year.

So, overall for the company, our production will be declining in the Bakken, but it will be moving up in the south. We've got higher rate of return projects in the south, we've got more opportunities, HBP acreage in the south.

And so that's why we want to focus more of our growth in the south right now than in the north. And I think you're going to see that throughout the Bakken play.

I think there's going to be a lot of operators and overall production in the Bakken will be dropping off over time for all operators.

Okay. That's helpful.

And obviously you guys did a very good job talking about how you're preserving liquidity and spending closer to cash flow here. I just wanted to get a better sense of what type of oil prices we need to see before you get more aggressive.

I think you're alluding to $60 to $70. Is that the right range before you start adding rigs?

Well, I think the market rewarding people for jumping in, increasing production, rig count today in low commodity prices, I just don't see that as something that ought to be happening. Let the market rebalance, supply and demand rebalance and come back in.

These reserves and these resource plays are not going anywhere and we all have a long future and that's the kind of way we look at it here. So I hope I answered your question.

All right. Thanks, guys.

Thank you. Good morning.

Hey, Brian.

Good morning.

Going back to the Springer program, can you just talk a little bit more about your path? You mentioned no drilling plans through year end.

Is that just simply the result of the need to be nimble in the commodity environment? Is it more related to the need to watch the density at wells, the well tests?

And what would you need to see to allocate more capital to Springer drilling? And where would the next wells be drilled within the play?

Okay. Well, really one of the biggest drivers for us now proceeding ahead, actually there's a couple things here.

One is we hate to sell this prolific production into this low-price environment, number one. And number two is that we don't need to because we're HBP'ing and actually delaying the Springer through our Woodford drilling.

So we're really in a real great seat here. We've got optionality.

We don't have to drill to delineate and assess the Springer and we've done our initial couple density tests here and we are monitoring results. And so as the Woodford drilling is HBP'ing and delineating the extent of the reservoir, we're monitoring the densities.

And when the time is right, and that would be when prices are more attractive, we can come in and start developing this right out of the chute. And so it's just an ideal setup for developing a reservoir.

If you're able to delineate it before you actually start developing it, then you don't really have to spend any really incremental dollars to get that done. And you asked where would we start drilling; we'd start drilling in the areas that we think we get the best results and start walking it out to the economic limits.

Great, thanks. And then just going back to the commodity environment that we're in and trying to focus actually a little bit on the Bakken and the SCOOP area, do you think in both the Bakken and in the SCOOP that there needs to be more consolidation of existing players?

Do you think that that's going to happen in the environment that we're in? And how, if at all, could or should Continental participate in that?

Well, I think it's likely you'd see some more consolidation if prices remain low. And Continental, we'll always keep our eyes open.

But right now we're focused on things we control and things we can accomplish and we'll let those types of things play out.

Great. Thank you.

Thanks, Brian.

Good morning.

Good morning.

Good morning.

Hi, Noel.

I realize you're just getting rolling with the STACK play, but across your acreage is your working assumption that it will be one of the formations that's prospective or productive across the acreage, or is the number somewhat higher than that at this point?

This is Glen Brown. The STACK play is, as defined by Newfield, is the top in the Meramec to the Basin.

The Woodford, we certainly recognize that there are multiple intervals in that. We're very early in the play, so we're really not out to speculate at this point about which levels might be more important, but we're certainly pleased with the results that we have so far with our first Meramec test.

And we will be delineating that as the year goes on and we get more wells.

And, Noel, I'll add, you're right. We are way early, we got our first test in here.

But there have been a lot of other industry wells drilled out here, which gives us some pretty good confidence on the repeatability, obviously, of this play. But early time results are still coming in from even those players.

And so but we're very optimistic about what we've got here as a widespread resource play. And what's really great about it is that in a time like this, we're able to add a whole new basically asset to our portfolio and we actually got to do it with really no acreage cost at all.

That 136,000 acres, combined some old legacy properties as well as other leasehold that we already had in-shop. So really this play has come to us at a very low cost.

Great. And about the SCOOP, as you've made a lot of progress delineating the play out there, do you have any thoughts or any impressions you can give us about the density that you're going to see sort of as the thickness varies throughout the play, anything in particular about maybe some of the – as it begins to thin out at the frontier?

Yeah, that's exactly what we're trying to do with our density test right now, we're trying to get a handle on that. We've done eight-well and 10-well densities, dual levels.

And others in the industry also have done a few tests out there as well. So it's a little early for us to give guidance or give some perspective on that because that's exactly what we're trying to find out.

And but it's a great question. I don't really have a clear answer for you right now.

I think for sure the industry across the board have been very pleased with the density test that's been performed here, so both in the Springer as well as the Woodford.

Thanks. That's all for me.

Thank you for taking my questions and also thanks for the helpful guidance around what 2016 might have looked like at various prices, et cetera. So one question I had though on that, you mentioned that you could hold exit production flat into 2016 at $1.8 billion to $2 billion.

Does that mean that you can hold that same production mix flat or the current production mix that you just had here in Q2 or with more drilling down in this SCOOP/STACK? Are we going to see a bit of a gassier mix as we look out into next year?

It's relatively flat. You might have a little bit more gas just because of the SCOOP, but remember in the SCOOP, we're a two stream reporting companies, so you've got a high liquids content down there to the benefits of rates of return.

So we're focused on, as Gary said, HBP'ing and also focused on rates of return and generating the best cash flow.

John, would you run your analysis, how much did the mix shift change on a percentage basis?

Not significant.

Okay. Thank you.

And then my follow up...

(46:18) it wasn't that significant percent maybe.

Thank you. And then my follow-up is for Harold.

Harold, you had mentioned and I know you've been working hard on trying to lift the U.S. export ban and you have a lot of confidence that you can get that done early this fall.

I don't think the market is quite there and believing that. So I'd like to know specifically, mechanically, how do you think it does get lifted?

Is this the President lifting it or does it go through Congress? Is it some sort of trade-off on the uranium deal whereby Congress provides more support if he agrees to lift the ban?

It's a good question, Pearce. Early on, we felt like – well, President, for sure, had the authority that he could do it by executive order.

He elected not to do that, I want to see legislation. We have confidence that he will sign a bill.

When he gets to his desk, this is something that has universal appeal across the board with every oil and gas industry group, organization, it's – will bode better for the public and cheaper gas prices in the future and everything else, if we can effect Brent market instead of just WTI. And so it's something that I feel certain about.

It's got good bipartisan support, both houses, the – Blu is here, Blue Hulsey and he and I have been working together on this. And he may have a comment as well.

But we feel very sure of that we'll see this go forward late September maybe – may get something done actually in September or early October. So, Bill, you have anything to add?

Harold, the only thing I would add is we've seen a movement out of the Senate Committee, out of Murkowski's Energy and Natural Resource Committee to bill, that language is in a bill that they approved right before recess, we're getting movement on the language. So we feel very confident we'll see that on the Senate floor soon in some form or fashion and we're in a very – we're very positive with the comments that the speakers made just recently coming out for the lifting the ban.

So we're getting a lot of support from each houses and actually getting some votes. So we feel very confident with the timeline.

Thank you very much.

Yes.

Yeah, thanks. So first question is the Anadarko Basin.

I guess historically known is it's fairly clay rich and more than perhaps some of the other shale op (49:17) plays. And, A, if that's the case, how it might vary between Meramec, Springer, SCOOP, and your land position and/or more importantly, do you see it having an impact at all on production rates?

And then I have a follow up.

Okay. Subash, are you asking, are these reservoirs – shale content of these reservoirs are affecting their performance?

Yeah, yeah. It's a clay content of the reservoirs affecting their performance.

We don't see that – we don't have that problem at all in the Woodford. I mean it is a shale reservoir, but we don't have problems with it and you might be referring to clay swelling or something like that.

And there's no issue there and we've got our first test up at STACK and right now it is performing really better than expectations.

Okay.

And so I really – I don't see it, as far as the Springer is concerned. Again, what we're targeting are our source beds (50:18), they're organic rich, we've got organic porosity in these rocks and we really avoid those more shale rich areas and go into those areas that are better targets.

Right.

And so I don't think I can answer the question any better. Harold, do you have something?

Well, yes. Obviously, we're into shale regimes there in all those, but I think the way that – with the PUDs that we're using and everything else, we're not having problem with swelling clays.

Okay. Got you.

Good answer. Thanks.

And my follow up, Harold, for you is that so if, let's say, back to the oil export question, if it was approved today, do you think you would see an immediate economic uplift in your oil sales? Or do you think it just provides some optionality that we don't currently have, so how do you see it in dollars and cents?

Well, it's obvious that you're going to see that uplift. You're going to see those prices to be the same.

That difference will only occur when we start trying to sell light sweet oil into market that had refineries that wouldn't handle it. Basically, all of our U.S.

refineries have been converted, two-thirds of them, to heavy sour crude that this product didn't work well in. So – and we couldn't sell to all those sweet refineries that's available to us outside the U.S.

and South Korea, for instance, and Europe and South America that need this product, need this oil. So these refineries have a captive market today and they don't have to pay up and they've taken $125 billion off the industry over just the past four years.

So, as you can tell, I feel fairly strong about it.

Okay, right. So just the final one on that, so the sales price would far more than offset the cost of transport to get to those Asian markets, et cetera?

Absolutely. Most of us are going to the Gulf and this is something can be turned on immediately.

We exported here in this country 1975, everything is there, the ships, the ship channel, pipelines, that can be turned on immediately, it's not like export natural gas that takes a while. This would be a tremendous industry going forward once that's accomplished.

And I got my fingers crossed for all of us. Thank you.

You bet. Thank you.

Good morning, guys. Just another one on the maintenance capital, is that $1.8 billion to $2 billion, is that based on your second half 2015 rig count or how is that different, I guess?

Second half rig count held flat.

Okay. And then...

(53:38) greater efficiencies we're seeing.

Okay. And then as we go out and as prices increase, would it just be equal adding rigs or more rigs would be allocated to the Mid-Con?

Well, we would probably tend to want to increase our rig count in the Mid-Con just because of the HBP'ing acreage, that'd probably be a driver.

Okay. And you made a comment in the release about at least 10 years of Bakken inventory close to 800,000 barrels a day.

Was that just your core area, is that what you know of today or can you maybe expand on that a little bit?

Yeah. Well, it is.

It represents – what we're trying to do, I guess, I should say, is we're trying to give a perspective of the depth of the inventory and we've got 10 years of 775 and it is – basically most of it's focused in the, what we call, the core area. But within that core area because this is an average or some that are higher than that, some that are lower than that as far as an EUR is concerned.

But we don't concentrate all our rigs in one area and so we have our rigs in different areas for operational efficiencies. And so the blended average, just so you guys can model it better, we give you this blended average so you can see that we're going to sustain in that kind of EUR average over 10-year period.

Okay. That's helpful.

Thanks, guys.

Thank you.

Yeah. Thanks.

Just want to ask a macro question, Continental has more knowledge on the Bakken than anyone. Based on all the efficiencies and shorter cycle times the industry has achieved in the last year in high grading into core, what's your estimate of rig count that the industry needs to run to hold the current Bakken production flat versus where we're at today?

Just trying to get a sense of how much we're undercapitalized in that play?

Well, I don't have that estimate, but I do believe the NDIC has come out with an estimate that – and I want to say, a few months ago it was 115 rigs, I believe. They thought they needed and I think that number has come down due to the efficiencies, but that's the number that I recall.

Okay, great. And then, when you referenced the 136,000 prospective acres for the STACK, does that include the position in both Dewey and Custer counties and I know there hasn't been much industry activity that far west, but do you think that the play boundaries could extend across your acreage position there?

Yes, it does go from Blaine out into Dewey County and I do think it laps into Custer a bit there as well.

Okay, great. And then last question, given where NGL prices are, just the dry gas window of the SCOOP come any more attractive on a relative basis similar to what we've seen in the Utica where operators have shifted activity from the liquids rich areas, and I did see that from the map, it looks like Continental actually did drill a couple of wells there in Western Grady County in the first half of 2015?

I guess discounting liquids, obviously the gas window gets to be more competitive with what's going on in the condensate window, but no, I just don't see that. And I think that the condensate windows got superior economics to us at this time.

Great. Thanks a lot.

Thank you.

Hi. Good morning.

A couple of clarification points on the CapEx discussion for 2016. The $2.5 billion for 2016 that would have growth in the mid to high-single digits, is that on an exit rate basis to exit rate basis or would that be year-over-year?

How should we be thinking about that? And then also on the $1.8 billion to $2 billion of CapEx still flat, is that just D&C?

Or is there other exploration in infrastructure CapEx that would be added to that?

Both of those indicators are on exit rate. Both of them include other – all components of CapEx, land acquisition, facilities whatnot, that they're all in.

Okay. Thank you.

You're welcome.

And then just a higher level strategy question, how do you balance the desire that Harold stated to find the strong plays during the downturn with the comments made at the start of the Q&A session on the ability to sell assets to maintain those financial objectives going forward, how do you balance those out?

I think you...

Go ahead, John.

When you're looking at your total portfolio, we are always looking for new opportunities, we're always looking to expand our asset base and in times like this, we find opportunities where it's not as competitive. Took our first lease in SCOOP back in 2008 for relatively low prices.

So you find some attractive opportunities with good economics. And we've got a proven team of finding and proven team with explorationists finding those opportunities.

And on the other side, we've got a lot of very valuable assets that at times we've monetized different assets to fund the development and expansion of higher growth assets that we have in the portfolio. So within our existing portfolio we have the ability if we choose to either be a JV or other structures to monetize a portion of our interest, but accelerate the growth of a undeveloped asset or we have PDP assets that have a lot of value on them that could fit into a number of corporate structures and could derive a lot of proceeds for us.

So it's a balance of we're always looking to expand, but we assess the portfolio continually.

Yeah, I was going to say I think our history shows we've been able to manage that and balance it. And my motto has always been I have more assets than I've got cash to develop.

And that gives you lots of optionality.

And historically, we've operated very lean and mean and not gotten out where we're having to monetize assets.

Thanks, guys. Thanks for the time.

Good morning, guys.

Hi, Matt.

Good morning.

Just one quick follow up on the hydrocarbon mix question. As we think about the back half of the year, Q2 I think you were around 66% oil.

Could you give us potentially a little bit of color on how we should think about that trending into Q3 and Q4, just given the commentary around the Bakken and SCOOP kind of growth in decline (1:00:57)?

You may see it a percent or two of gas here. These two big pads we've brought on to Honeycutt and Poteet have been tremendous in terms of volumes, they continue to hold in there well.

So you're getting more and that's giving you a little bit gassier mix. And as we've said, we're also keeping a little more CapEx in there relative to the Bakken just because the rates of return now and HBP'ing.

I want point out, though, just to make clear, that is not necessarily a long-term trend that you're going to see. As oil prices recover, you will see a move back into the Bakken.

And we've got a very significant inventory there and we are still committed to being an oil company.

And we put Springer basically on hold right now.

Yeah.

We'll monitor the density development and allow it to be delineated before we start moving ahead to develop it. So that's still to be put in the mix down in SCOOP in...

Good optionality.

Great. And then just as a follow-up question, the initial well in the STACK looks extremely encouraging.

I was curious based on your results plus the industry data that you have, how much of that 136,000 acres you think you've delineated so far? And then I guess secondarily alongside that, how much of the acreage you potentially think is within the liquids-rich window of the play?

Glen Brown here. I'll answer that.

The play has started out developing from east to west through Kingfisher County. And we've just now entered with our well and a few recent wells entered the pressure window.

And we obviously are in the true oil window a portion of our acreage. We believe that covers 25% of our acreage position.

We think that 50% of additional acreage position is covered by liquid rich, with the remaining 25% being in dry gas. And we will move this development systematically towards the west, but I would point out that way over in Dewey County there are some substantial wells already in the far northwest part of our play.

Thank you very much.

Thank you.

Hi. John, you mentioned earlier that your budget doesn't anticipate any capital markets activity in the second half and you fleshed out the thought process on equity issuance a bit further.

But I'm just wondering given that you do have a revolver balance and you have some higher coupon debts callable this fall, where does debt issuance fit in, if at all?

I think those bonds that you're referring to, the $200 million of 7.375% bonds, I assume. And I'd say that's a math exercise.

They're callable at some point in October. When we get to that point, then we'll look to see where they're at.

And if we've got enough capacity that we could do that and then certainly put those on the revolver or turn them out in the market in a variety of fashions if we chose to. We haven't made that decision yet, but it's certainly something that we see out there in the quarter that we'll be deciding on.

Okay. And then in terms of the revolver balance itself as it stands today, how long are you comfortable running with a balance of that size?

If you go back six months, seven months, we had a revolver commitment of $1.5 billion or $1.75 billion and raised that to $2.5 billion. And right now, we've got $1.3 billion of capacity.

We're leveling off on our level of spend. We're focused on trying, even at lower prices, to get to cash flow neutrality for the back half of the year.

We were there in June and I think we were there in July also, or we were positive in June. So we're going to focus on that for the back half.

And with that, I've got ample liquidity to cover that. And as we see the markets improve and prices come up, obviously those metrics are going to improve dramatically.

But the mode we're in now is we don't want to take on additional debt. We want to preserve that significant liquidity that we have.

Did I answer you?

Thanks very much, John. Thank you.

Okay. Thank you.

Yes, I just wanted one clarification on the 2016. Just because the gas mix grew so much and oil grew some from 1Q to 2Q, but gas grew a lot faster.

When you're talking about the gas mix and oil mix being about flat into 2016, that was based on where the mix currently is or where the mix started this year? So would you expect a 70%-ish mix or a 65%-ish mix?

I'd expect just for 2016, it depends. Like I said, if oil prices come back, you're going to see capital going back into the Bakken.

And when you see that the oil percentage is going to go up also is when oil prices come back, we're going to start drilling the Springer. What we're trying to do right now is hold our old assets for the future and focus on HBP'ing and delineating down here.

We get a little better rate of return with that. If you stay in this price environment, with that maintenance capital, you're probably going to see a gas mix in the mid 60% range.

Okay.

Plus or minus. 65%, 66%, somewhere in there, maybe 64%.

I appreciate that.

And part of it is just the huge volumetric effect that we've got from the Honeycutt and the Poteet pads and then bringing Northwest Cana on at 80% type rates of return because of the carry, but we started drilling in there and that was incremental.

Okay. Thanks for the clarification.

I appreciate it.

Absolutely.

Thanks, everybody, for joining us on the call this morning. We are in some turbulent times in this industry.

We expect those to start making a change for the better in a very short order and we will be back to you next quarter. Thank you very much.