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Range Resources (RRC) Q1 2017 Results - Earnings Call Transcript

Seeking Alpha logo Seeking Alpha 4/26/2017 SA Transcripts

Range Resources Corp. (RRC)

Q1 2017 Earnings Call

April 25, 2017 9:00 am ET


Laith Sando - Range Resources Corp.

Jeffrey L. Ventura - Range Resources Corp.

Ray N. Walker, Jr. - Range Resources Corp.

Roger S. Manny - Range Resources Corp.

Alan W. Farquharson - Range Resources Corp.


Daniel Eugene McSpirit - BMO Capital Markets (United States)

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Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Ronald E. Mills - Johnson Rice & Co. LLC

Subash Chandra - Guggenheim Securities LLC

Robert Scott Morris - Citigroup Global Markets, Inc.

Brian Singer - Goldman Sachs & Co.

Blaise Matthew Angelico - IBERIA Capital Partners LLC



Welcome to the Range Resources First Quarter 2017 Earnings Conference Call. This call is being recorded. Statements contained in this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties which could cause actual results to differ materially from those in the forward-looking statements. After the speakers' remarks, there will be a question and answer period.

At this time, I'd like to turn the call over to Mr. Laith Sando, Vice President, Investor Relations at Range Resources. Please go ahead.

Laith Sando - Range Resources Corp.

Thank you, operator. Good morning everyone, and thank you for joining Range's first quarter earnings call. The speakers on today's call are Jeff Ventura, Chief Executive Officer; Ray Walker, Chief Operating Officer; and Roger Manny, Chief Financial Officer.

Hopefully you've had the chance to review the press release and updated investor presentation that we've posted on our website. We'll be referencing some of the those slides this morning. We also filed our 10-Q with the SEC yesterday. It's available on our website under the Investors tab, or you can access it using the SEC's EDGAR system.

Before we begin, let me also point out that we'll be referencing certain non-GAAP measures on today's call. Our press release provides reconciliations of these to the most comparable GAAP figures. In addition, we've posted supplemental tables on our website to assist in the calculation of these non-GAAP measures. The supplemental tables also provide calculated natural gas differentials for the upcoming quarter and detailed hedging information for all products.

With that, let me turn the call over to Jeff.

Jeffrey L. Ventura - Range Resources Corp.

Thank you, Laith. Improving pricing differentials driving expanding margins is the theme of the first quarter and what we believe will be a continuing theme for Range in 2017 and 2018. Coupling the enhanced margins with the lowest PUD development cost for any of our oil or gas peers, we calculate our unhedged recycle ratio as approximately 3 times.

The story is ratified by independent work from well respected firms and analysts, with one such report included in our new presentation. It examines recycle ratios across the Delaware Basin, Midland Basin, the SCOOP/STACK play, the Bakken, the Eagle Ford and the Marcellus. This work includes a number of very high quality oil and gas companies. Based on this analysis, Range has one of the top recycle ratios of any company whether oil or gas and in any basin. We believe this is a key indicator of long-term success driving above average profitability in a normalized price environment or strengthened stability in the down cycle.

Moving back to margin expansion, improving price differentials for natural gas, NGLs and condensate are expected for 2017. A full year of transportation on our Gulf Expansion Phase 1 pipeline project and a full year of contribution from our near to market North Louisiana assets are resulting in our natural gas differential for this year improving to approximately NYMEX less $0.30. Later this year, we're expecting Rayne/Leach Xpress at their Southwest and Rover Phase 2 pipelines to commence operations. These transportation projects should result in further improvement in our 2018 differentials.

Per barrel NGL pricing for 2017 is projected to be 28% to 30% of WTI. A full year of Mariner East plus NGL sales from North Louisiana are the main contributors for the increase in realized price. Looking forward to 2018, fundamentals suggest that higher demand for ethane and propane from the petrochemical sector and exports can improve our pricing differentials further next year.

Our condensate pricing differential per barrel for 2017 is projected to be WTI less about $5.50. This is driven by a full year of our new marketing agreement for Marcellus condensate and a full year of North Louisiana condensate sales. Importantly, this pricing differential represent a 40% improvement over our 2016 condensate differential. This improvement in pricing across gas, NGLs and condensate coupled with one of the lowest cost structures in the industry, has resulted in the margin improvement we're seeing in the first quarter and are projecting for the full year. Capital efficiency in 2017 will continue to improve as we're targeting over 9,000 foot laterals in Pennsylvania and we're driving down the cost of drilling complete wells in North Louisiana. Ray will discuss our operational highlights next and provide more detail on our plans.

With the first quarter in the books, 2017 is shaping up to be a good year for Range. Importantly, we expect our class-leading recycle ratio in 2017 to continue into 2018 and beyond as Range is one of the few companies in the industry with a decade plus of high quality drilling locations. We have a resource potential of approximately 100 Tcfe as compared to our year-end proved reserves of 12.1 Tcfe. Our resource potential does not include the highly prospective Utica, which will drive our ratio of resource potential to proved reserves even higher.

As shown on slides 23 and 24, in the southwest portion of the Marcellus, Range has the highest estimated ultimate recovery per foot, lowest finding and development costs and lowest breakeven costs. We have a high quality asset position in North Louisiana and as shown on slide 13, we've made significant progress adding value since the acquisition was announced last May. Looking forward, Range remains well positioned to drive value for years to come.

I'll now turn the call over to Ray to discuss our operations.

Ray N. Walker, Jr. - Range Resources Corp.

Thanks, Jeff. Production for the first quarter came in at 1.93 Bcf equivalent per day, and guidance for the second quarter is flat to the first quarter of 2017, or 1.93 Bcf equivalent per day, and we remain on track for annual growth of 33% to 35% as the company's production growth is weighted towards the back half of the year.

Before walking through operations, I'd like to spend a few minutes on our production growth for the rest of 2017 and how this sets us up for 2018. In Appalachia, we brought to sales in the first quarter less than 20% of our expected wells for the year, so growth in the back half of the year should look really good. In North Louisiana, we expect to bring to sales 29 additional wells in the second half of 2017, also providing solid growth in the second half of the year. We delivered on our expected production for the first quarter of 2017 in both Appalachia and North Louisiana.

And in Terryville, we expect wells going forward will generate better growth than the group of wells turned to sales in the first quarter. To illustrate, let's compare and contrast our first quarter activity with our expectations going forward. As discussed on the last couple earnings calls, 18 of the Terryville wells brought to sales in the first quarter were drilled prior to the acquisition, many of them over a year ago. As result of completing such a large swath of wells at one time, which was 27 during the first quarter, and because of the location of many of these wells, approximately 40 million cubic feet equivalent per day of offset production was shut in to minimize the frac hits.

The shut-in production does not come back all at once, but will come back throughout the year via flatter declines. Going forward, we're planning a more balanced approach both in terms of activity and planning the well locations to help minimize the impact on offset production. As discussed before, we've implemented a completely different flow-back in early production protocol. The wells will now be opened up under designed, constrained conditions, allowing the use of more cost effective facilities and the minimization of expensive flow-back rental equipment. We believe this will improve the overall project returns.

What it means is, that we won't see the initial 30-day rates that you would have seen in the past. And we've changed production operations in the field. In addition to a different approach to flow-backs, we're also implementing Range's safety, facility and production protocols. One example is eliminating production of the annulus. This practice, while common in some areas, is not the preferred practice with the equipment that is currently in place. These design and operational changes resulted in cutting back production by approximately 30 million cubic feet equivalent per day for the year. Of course, this simply curtails production, and we expect to get that production back via a flatter decline.

In the first quarter, we also tested some meaningful step-outs in Terryville that will help to further delineate and de-risk our well inventory. Some of these wells were in areas perceived as the edges of the field due to poor historical results. While the results from the new wells are early, they are very encouraging and are in part the result of improved targeting. With lower drilling and completion costs, the encouraging early well results and the ability in the future to incorporate better mapping and seismic, we believe these areas hold significant potential.

As part of that same process of better understanding the field's ultimate potential, the first quarter included wells that had been drilled pre-acquisition in some of the Pink horizons. Completing these wells will provide us a better understanding of the resource potential over the coming years.

Going forward, we'll continue to be focused on the Upper and Lower Red, while occasionally drilling other horizons and extension wells to optimize our full development plans. This is similar to our approach in Appalachia, that is, focusing on the Marcellus while unlocking the Utica and Upper Devonian opportunities over time.

So while the first quarter was a great quarter operationally and financially, we're really looking forward to the second half of this year, as we continue to build on our operational successes in both North Louisiana and Appalachia.

Hitting on some of the operational highlights for the quarter, we'll start with Appalachia, where we're directing approximately two thirds of our capital spend. We continue to make great strides in unit cost reductions, improving well performance and capital efficiency.

I'd like to take a few minutes now and walk through some updates on the drilling side in Appalachia. Our team has now drilled the longest Marcellus lateral in Pennsylvania and three of the top four longest laterals in the entire basin. In the first quarter, we drilled three laterals over 15,000 feet and seven laterals over 10,000 feet. We're achieving a 67% increase in daily lateral footage drilled versus a year ago.

Combining our drilling performance and planning efforts, our average lateral length drilled this year will be approximately 9,000 feet. These improvements can be attributed to four things. We've upgraded our rig fleet to higher horsepower and higher pressure rated equipment. We've adopted and greatly improved the efficiency of our rotary steerable tools. The team has redesigned our current mud systems, and a real focus on key performance indicators that trigger real and measurable success. And two final things on the drilling side, we've accomplished all of this while narrowing our lateral target to a 10-foot window, at the same time drilling faster while lowering cost from last year on a per foot basis by over 30%. And it's been almost two years since the team has had to sidetrack a wellbore. Needless to say, we're really proud of their accomplishments.

On the completions, facilities, water and production front, we're continuing to innovate and improve efficiencies and cost. We're fine tuning frac designs and zipper frac operations, and I expect we'll continue to do so for years ahead. Even with some forecasted pressure on service costs, our cost per stage and our cost per foot of completed lateral should continue to improve throughout 2017.

Facility costs should continue to improve and LOE continues to trend in the right direction. Any way you look at the data, Range has the lowest well cost, including facilities, of any operator in the southwest portion of the basin, and we expect those costs will continue to improve. One significant and unique advantage that we have is the extensive network of existing infrastructure in pads. We're planning for approximately a third of our 2017 wells on existing pads, with as much as half of our wells in 2018. This will drive down our costs significantly, by as much as $200,000 to $500,000 per well.

On the well performance side, we continue to improve completion designs and see impressive results. As an example, I want to highlight a couple of liquids-rich pads that we brought online during the first quarter. In the wet area, we brought online a three-well pad with average lateral length of 7,186 feet, completed with 37 stages per well that produced net-to-sales under designed constrained conditions at a max 24-hour rate of 35.3 million cubic feet equivalent per day per well.

In the super-rich area, we have a four-well pad with average lateral lengths of 10,772 feet completed with 54 stages per well, but have only been able to put two of the wells to sales so far. The reason why is that they're some of the best liquids rich wells in the basin. Those two wells have averaged over 31.4 million cubic feet equivalent per day, each well, or over 62.8 million cubic feet equivalent per day combined with 69% liquids, again under designed constrained conditions net-to-sales for a max 24-hour rate.

As those two wells decline, we'll be adding the other two wells to sales as capacity frees up in the system. It's important to point out that this pad is near the planned Harmon Creek processing plant in a lightly drilled super-rich area. And we have plans to develop additional wells and pads in this area going forward.

Clearly, these two pads illustrate the quality of our low risk, long lateral inventory in Appalachia in the dry, wet and super-rich areas. These types of results, when combined with going back on to existing pads with existing gathering and compression infrastructure generate liquids-rich drilling economics that are among the best in the business. Like I've said in the past, we literally have thousands of these types of opportunities and I still don't believe we've drilled our best well yet.

As a quick update on the Utica, I believe it's worth pointing out the updated map in our presentation on page 44. Of particular note, we've highlighted the recent activity, including some direct offsets to our acreage currently being drilled that will clearly enhance our 400,000 net acre position further.

We'll continue to monitor those wells and other Utica activity in Pennsylvania as we go forward. Our best well remains as one of the top four Utica wells in the play. We believe it will hold flat for close to 400 days and the EUR looks to be around 3.25 Bcf per 1,000 foot. Again, essentially all our acreage is HBP'd and we believe the Utica play will play a complementary and important role in the future.

Shifting to North Louisiana, we're excited about the progress we've achieved in just a little over six months and believe we're on track to exceed our original acquisition expectations. We're in line with forecasted production and cash cost, and we're expecting solid growth in the second half of the year, while drilling and completion cost have improved further and faster than we expected. We've reduced our average all-in well cost for a 7,500 foot lateral by another $300,000 to $7.4 million while reducing drilling time, refining the target window and staying 100% in zone.

This is now $1.3 million or 15% below the $8.7 million cost last September, which obviously has a major impact on the economics. Like we've discussed, this lower cost will open up additional inventory from various horizons across our acreage positions. Our capital plan and the $7.4 million well cost in North Louisiana has baked in our forecast for service pricing increases for the year. For some services, those increases could range from 5% to 25%. However, as evidenced by our well cost, we fully expect that improvements in our operations and designs will more than offset the service price increases.

As mentioned earlier, our 2017 North Louisiana program includes drilling, delineating and de-risking our well inventory in Terryville. This plan consists of wells in the various Lower Cotton Valley intervals that will lead to an improved understanding and mapping of the reservoirs alongside the acquisition of additional science work directed at determining optimum targeting and completion design. We are acquiring additional seismic along the southwestern and southeastern portions of the field to help calibrate the reservoir mapping and well results.

During the quarter, we completed 27 wells made up of 19 Upper Reds, five Lower Reds and three Pinks. And we're producing these wells much differently than the historical practice, mainly under designed facility constraints, resulting in lower cost and flatter declines. We believe that this new approach of adopting more cost effective facilities, combined with better targeting and completions will drive the next step in development for the Terryville field.

To put some context around 2017 well activity, there are really three groups of wells. The first group is the wells that we simply call the pre-Range wells. In essence, we may have taken over operations in one phase or another, but essentially they were planned and designed using historical practices. This was 21 of the 27 wells in the first quarter, and 18 of them were drilled almost a year ago.

The second group of wells, which six of the 27 fall into this group, is those wells where Range may not have been able to pick the location or the formation, but we did have some influence in the targeting and drilling of the well. And then the last group are the Range wells, where we picked the location, formation, target and designed them from start to finish. The majority of the remaining 29 wells for the year, again which are weighted to the last half of the year, fall into this group and we've only recently begun completing the first of these wells. We're excited about what we see so far, and I look forward to updating those results throughout the year as we gather that performance data and build our reservoir models and development plans for the future.

As an update on the extension area activity, results continue to be encouraging from the two of the wells that we announced last quarter. Each of the two wells, each located in separate Terryville sized fault blocks, one to the east, and one to the west of the Vernon Field have cumulative production to-date of approximately 1 Bcf each. As a result, plans are underway to offset each well with another horizontal well.

Additionally, in the extension area, we have two pilot holes, one partially completed lateral that we're currently testing and we'll be starting a couple of new vertical wells designed to test multiple targets on an individual basis. This allows us to determine reservoir and rock properties while performing specific diagnostics to identify the best lateral targets. With over 400 Bcf per square mile and up to six target intervals, the potential is large. Again, we remain focused on Terryville while methodically testing and delineating the extension areas over time.

In the Marcellus, we're continuing to improve returns through lower cost and improved well performance and we continue to develop our extensive inventory of core locations with longer laterals. In North Louisiana, we're ahead of our acquisition case and believe we'll continue to make progress going forward. We're on track for our production growth guidance for 2017 and 2018 is shaping up very well.

Now, I'd like to turn the call over to Roger to discuss the financials.

Roger S. Manny - Range Resources Corp.

Thank you, Ray. The first quarter of 2017 builds upon the excellent fourth quarter of 2016 with further improvements in top line growth, cost control, margins and bottom line net income and cash flow. Net income on a GAAP basis for the first quarter was $170 million, while earnings using common analyst methodology, which excludes non-cash derivative mark-to-market entries and non-recurring items was $61 million.

Cash flow for the first quarter was $258 million, 2.5 times the first quarter of last year's $99 million figure. Cash flow per fully diluted share was $1.05, 78% higher than last year's per share figure of $0.59. EBITDAX for the first quarter of 2017 was $303 million, compared to last year's $135 million amount. First quarter 2017 cash margin, at $1.47 per Mcfe, was almost double that of last year's cash margin at $0.77.

One notable achievement in the first quarter of 2017 was that for the first time since 2014, Range was solidly profitable without any contribution from our hedge book, with our unhedged recycle ratio approaching 3 times and continued margin and capital efficiency improvements projected, future quarters should be much more like the past two quarters than the preceding seven.

Moving to the expense performance for the first quarter, all of our expense results came in at or below guidance. Detailed expense guidance for the second quarter of this year may be found in the earnings release.

Turning to the balance sheet, like last year, we ended the first quarter with less debt than we entered as our spending outflows were less than our cash inflows. Our debt-to-EBITDAX leverage ratio, calculated using a first quarter annualized EBITDAX, was 3.1 times and our book debt-to-capitalization ratio is 40%.

Additional hedges were selectively added during the first quarter to be already well established 2017 and 2018 hedge positions and we initiated our first hedge on 2019 production. Presently, over 75% of our 2017 natural gas production is hedged with an average floor price of $3.22 an Mmbtu. Additional hedges were added to our oil and NGL book during the first quarter as well. Full disclosure of our hedge price and volume positions maybe found in the 10-Q, earnings release and Range website.

The first quarter of each year has historically been a strong one financially. The reason for this first quarter strength is usually the peak of winter weather and the resulting strong demand and higher prices for our products. In 2017, the story is very different. This winter we experienced the second warmest first quarter in 30 years, based on gas weighted heating degree days, and the second warmest first quarter in 123 years based on average temperature.

However, our first quarter cash flow of $258 million was roughly the same as our cash flow for the first quarter of 2014, a year when we had the coldest first quarter in 30 years. The reason that our first quarter financial performance in the second warmest winter in 30 years is on par with the coldest winter in 30 years is a result of capital-efficient growth and the improved transportation, marketing and cost control measures Range has been working on for the past 10 years. The margin improvements we are seeing from our relentless cost control, the capital efficiencies from technology and the quality of our rock, combined with the marketing uplift from our unique natural gas and NGL marketing projects, have made Range's financial performance much more durable regardless of the weather.

Now Jeff, back to you.

Jeffrey L. Ventura - Range Resources Corp.

Operator, let's open it up for Q&A.

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