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Current RRC Stock Info

Range Resources Corporation (ticker: RRC) is a leading independent oil and natural gas producer with operations focused in Appalachia and the southwest region of the United States. The Company pursues an organic growth strategy targeting high return, low-cost projects within its large inventory of low risk, development drilling opportunities. The Company is headquartered in Fort Worth, Texas.

Range Resources announced its Q3’13 results on October 30, 2013. Its production over the prior year included increases of 43% in condensate, 28% in NGL and 19% in natural gas. Total production volumes rose 21%, and volume reached a record high of 960 Mmcfe/d. Continued success in the Marcellus Shale drove the landmark production rates, as RRC exceeded its guidance projections and reduced unit costs by 12%. Adjusted cash flow was $244 million, a 29% increase TTM. Gas price realizations compared to local pricing indices were $0.41 higher in the southwest Marcellus and $0.56 higher in the northeast Marcellus. The Mariner West Project is expected to be operational in November 2013, and will export ethane to Sarnia, Canada. When all three ethane solutions are fully operational, Range’s average price equates to a natural gas price of $4.13 net of transportation cost. An additional 8% of propane recovery via ethane extraction could add an additional $0.40 to $0.50 of equivalent natural gas price.

Operations Update

Currently, Range has contracts in place for approximately 1.0 Bcf/d of firm capacity increasing to 1.5 Bcf/d by 2015 at an average cost of $0.23 per Mmbtu.

In southwest Pennsylvania, the division brought online 26 Marcellus wells, with 24 (23 net) wells in the super-rich area and two wells in the dry gas area. Initial production of the super-rich wells averaged 2,657 (2,122 net) BOEPD per day with 66% liquids assuming 80% ethane extraction. The other 17 super rich wells have been online for 240 days and are 43% above the 1.32 MMBOE type curve. Among liquids rich wells, with initial production of 60% liquids or greater, Range believes that it has drilled five of the top ten producing wells in the Appalachian Basin. Normalizing results, on a per 1,000 lateral foot basis, Range has drilled eight of the top ten liquids rich producing wells.

In its Midcontinent division, Range completed a 12-mile step-out well in October 2013, and averaged 330 BOEPD for 30 days with 94% liquids. Larger frac stimulations were tested on four wells, and production rates reached 45% above the 600 MBOE curve for the first 65 days. A total of 7 (6.8 net) wells were turned to sales during the quarter with average lateral lengths of 3,742 feet with 21 frac stages. The initial production on these wells averaged 622 BOEPD (493 net) with 75% liquids – the highest average for any quarter to date. RRC’s operating costs per well have remained at $3.2 million despite the larger fracs. Range anticipates bringing online four additional horizontal Mississippian wells with larger frac stimulations during Q4’13.

2013 Guidance

Production for Q4’13 is expected to be approximately 1.0 Bcfe/d, with 25% liquids. If reached, the company will set another production record. Approximately 196 wells in the Marcellus and Horizontal Mississippian are expected to turn to sales just prior to year-end, and will therefore not have a significant impact on its Q4’13 production.

Range Resources Commentary

RRC held a conference call following the earnings release on October 30, 2013. Jeffrey Ventura, President and Chief Executive Officer of RRC, said: “Given Range’s large, high quality, low risk acreage position and drilling inventory, we continue to believe that we have 20% to 25% line of sight growth for many years. Led by approximately 1 million net acre position in Pennsylvania, we project that we’ll consistently drive up both production and reserves on a per share basis debt adjusted for years to come.”

Ventura also commented on RRC’s aggressive approach to its Mississippian assets. “All of our teams are focused on lowering costs and becoming more capital efficient, so earlier this year we tried some smaller frac jobs, but the results didn’t look that good. We’ve now gone back to pumping on much larger frac and those wells look really, really encouraging… It could be a really nice oil play at 4,500 foot or less in Oklahoma…”

He added: “It’s only four wells and it’s only 65 days, but we’ll do some more delineation wells, step it out, we’ll prove up some more areas and we’ll continue to evaluate the larger frac designs. But this is still emerging and you know, we’ll consider all that when we present the budget to the board in December.”

An increased rig count in the Marcellus can be credited to increased efficiency, Ventura said, and recovery rates after infill potential could climb into the 40% range. Ray Walker, Chief Operating Officer, touched on cost efficiency in the area. He said: “We’ve seen well costs come down and well performance go up. We’re beginning to go back into some of these locations that already had the location build, the water impoundment’s there the facilities are already there. We’re already doing that in a small way as we go back in to drill additional 80 acre wells. We’re really confident of what we’re going to find in our Utica testing, and we’ve already cracked the code on the Upper Devonian. We’ve only drilled about 7% of the acreage, so we’ve still got a long ways to go.”

Research Commentary

Oil & Gas 360® compiled a few paragraphs from research analysts who wrote on Range Resources following the announcement. OAG360 suggests that you contact the analyst and/or salesperson to receive a complete copy of the report. Please read the important disclosures at the end of this note.

UBS Investment Research Note – 10.30.13

RRC reiterated confidence in reaching the high end of 2013 production growth guidance of 20-25%, with liquids expected to grow in excess of 20-25%. Production will continue to be driven primarily by ramping activity in the liquids-rich areas of the Marcellus and the oily Horizontal Miss, while RRC plans to limit its dry gas drilling activity in Northeast PA. RRC provided 4Q13 production guidance of ~1 Bcfed, up 4% from the 3Q13 level of 960 MMcfed. While 4Q guidance is largely in line with consensus of 1.02 Bcfed, we would note RRC’s historical propensity to provide conservative production guidance, which it then beats. As shown in Figure 1, RRC has beat production guidance for 10 consecutive quarters and 13 of the last 14 quarters. We forecast 4Q production of 1.02 Bcfed – slightly above guidance but in line with consensus – and are maintaining our 2013 production growth estimate of 25%, which assumes 33% liquids growth and 23% dry gas growth. We forecast 2014 production growth of 22%, compared to consensus growth expectations of 23% and RRC’s long term target of 20-25% per annum.

Raymond James Equity Research Note – 10.30.13

Recommendation: Range has laudably gotten in front of gas marketing issues, and is poised to reap the benefits from additional market access during a time when Marcellus producers face ongoing infrastructure headwinds. Considerable variability still exists heading into 2014, but we expect margins to expand as NGL volumes ramp. Operationally, management highlighted improved well performance and lower costs during 3Q13 too. But, given Range’s premium multiple, we reiterate our Market Perform rating. We will listen to today’s call for more detail on volume/pricing forecasts.

* Range posts beat: For 3Q13, RRC reported adjusted EPS/CFPS/EBITDA of $0.35/$1.51/$290 million vs. our $0.34/$1.35/$269 million and consensus $0.30/$1.40/$276 million. The beat came as a result of a lower cost profile in light of pre-released production and pricing (recap page 2), notably our operating cost (-9%) forecast.

* Marcellus marketing: While its peers in NE PA see wider differentials, Range is benefitting from the marketing efforts undertaken the past couple of years. Near-term, RRC will sell 15 MBD of ethane to Nova Chemicals starting in 1Q14, as Mariner West pipeline becomes fully functional. Longer term, Range will be ramping to ~1.5 Bcf/d of takeaway capacity by YE15 (980 MMcf/d transport capacity, 500 MMcf/d sales contracts) and adding another 40 MBD of ethane and propane capacity.

* Outspending again. For next year, we estimate RRC outspending cash flow by ~$480 million after $920 million of discretionary cash flow as a higher liquids cut is impacted by our bearish oil forecast. We model the company’s net debt/EBITDA climbing back above 3x by YE14 (vs. 2.8x now and large cap peers <2x). Range layered in additional hedges in the quarter to protect some cash flows, having 58%/65% of gas/oil hedged next year.

* Trimming estimates: We are trimming our estimates to account for our updated production and cost profile. We now model the NGL stream making up a large portion of next year’s projected production growth, causing us to scale back gas growth, ceteris paribus. Still, we think this assumption will prove conservative as Marcellus EURs continue to benefit from tighter cluster spacings and longer laterals.

Barclays Note – 10.30.13

We expect a positive reaction to RRC’s 3Q earnings report and operational update. 3Q “clean” EPS was $0.35 vs. our and consensus estimate of $0.30. The beat relative to our estimates is attributable to lower than forecasted (and guided) transportation and operating expenses. Revenues were in line with our estimate, with higher-than-modeled production offsetting lower revenues (note both production and prices were reported on October 17th but were not reflected in our estimates). As previously reported the Mariner West Project started taking ethane production to Sarnia, Canada in late July and is expected to be fully operational in November. Range announced it has more than doubled its contracted firm transportation capacity from 650 mmcf/d by year-end 2015 to 1.5 bcf/d by year-end 2015 (at an average cost of $0.23/mcf). The company has secured additional 200 mmcf/d by year-end 2017 and is in discussions to add additional firm capacity on several large take-away systems. Operationally, Range reported strong results from both the southern and northern Marcellus areas, as well as from the Mississippian.

Operational update:

• In the super-rich area in the Marcellus, 24 wells were brought online during the quarter. RRC reported the results assuming 80% “theoretical” ethane extraction – Range’s reported rates are not directly comparable to others in the region that are reporting volumes assuming ethane rejection. The assumption of ethane extraction increases “BOE” volumes but sometimes results in lower revenues – for that share of ethane that is being transported to the Gulf Coast (36% of RRCs existing ethane contractual agreements). While we don’t think RRC is extracting 80% of its ethane today, its NGL marketing plans appear further advanced than its competitors in the region – and it will likely receive better ethane prices than peers due to its Mariner arrangements. At any rate the wells averaged 24-hour theoretical production rates of 2,657 mboepd including 66% liquids (with 80% ethane extraction), seemingly stronger than the 2Q 24-hour average of 1,863 mboepd including 65% liquids (although it is unclear that the averages for the two quarters are directly comparable because of ethane extraction).

• In dry-gas area in northeast Marcellus, three step-out wells averaged 24-hour production rates of over 21 mmcf/d, exceeding 2Q averages by 70%.

• In the Mississippian, larger frac jobs on four wells in resulted in 65-day production tracking 45% above the company’s 600Mboe type curve.

Range excludes a number of recurring costs from its reported “clean” EPS of $0.35 per share. Our and consensus EPS estimate was $0.30.

• RRC reported 3Q net income of $19.2mm or $0.12 per share, including 1) $6mm loss on sale of properties (pre-tax), 2) $33.4mm loss on unrealized derivatives (pre-tax), 3) $18.7mm of abandonment and impairment charges (pre-tax), 4) $3.7mm loss on gas-blending (pre-tax), 5) $.324mm on lawsuit settlements (pre-tax), 6) $13.2 million of total non-cash stock based compensation (included in broker natural gas and marketing, direct operating, exploration and G&A expense items) (pre-tax) and 7) -$2.2 million of deferred compensation (pre-tax). Many oil and gas companies view stock based compensation and impairment of oil and gas properties – which accounted for roughly half of the $0.23/share EPS adjustment — as normal costs of doing business.

3Q earnings analysis

• Total company production of 959 mmcfepd was reported on October 17th and was ~1% higher than our estimate of 950 and above the high-end of management’s 945-950 mmcfepd guidance. RRC noted that ethane sold on the Mariner West project contributed 876 bpd to the NGL mix.

  • Natural gas production averaged 739 mmcfpd, up 4% sequentially
  • NGL production averaged 25.7 mbpd, up 10% sequentially
  • Oil production averaged 11.1 mbpd, up 16% sequentially

• Price realizations (including hedges gains) were also reported on October 17th. Natural gas price realizations of $4.03/mcf were ~4% weaker than our forecast and oil price realization of $85.46/bbl was ~5% weaker than our forecast. NGL price realization of $31.08/bbl was ~6% higher than our forecast.

• Operating expenses of $0.35/mcfe were 10% better than our forecast and below management’s guidance of $0.38-0.40/mcfe guidance. Q4 guidance suggests continued strong operating expenses at $0.34-0.36/mcfe.

• Transportation expenses of $0.69/mcfe were ~15% better than our forecast and below management’s guidance of $0.80-0.82/mcfe guidance. Q4 guidance shows an increase in costs to $0.77-0.79/mcfe.

• DD&A of $1.48/mcfe was in line with our forecast and within RRC’s guidance of $1.46-1.48/mcfe. Q4 guidance is in line with Q3 rates.

• Recurring G&A of $45 million (excluding non-cash item and lawsuit settlement) was 8% lower than our forecast.

• Exploration expense of $20.5 million was in line with our forecast and within RRC’s $19-21 million guidance. Q4 guidance is for $16-17 million.

• Q4 guidance for unproved property impairment expense is $14-16 million – consistent with the $15.3 million quarterly run rate this year. But investors may want to leave this out of their model so they can compare their estimates to the Non-GAAP financial measure that Range refers to as “Adjusted net income comparable to analysts’ estimates” in its press releases

• RRC reported clean tax rate of 38% vs. our 37% forecast

Stifel Note – 10.30.13

3Q13 Earnings Summary

RRC reported 3Q13 EPS/CFPS of $0.35/$1.40 topping our estimates of $0.27/$1.27 and Street consensus of $0.30/$1.40. Results beat our estimates on transportation costs (-15%) and LOE (-10%) partially offset by G&A (+21%) (Figure 1).

Pre-released production of 960 MMcfe/d increased 22% y/y and 6% from 2Q13. The production mix moved slightly towards liquids (16% NGL, 7% oil, and 77% gas from 15%/6%/78% in 2Q13).

Insulated from Appalachian Differentials

RRC’s 3Q13 Marcellus realized gas price was $0.06 below the NYMEX benchmark average compared to some pipelines in the region where the differential averaged $0.41 to 0.56/Mcf. Ten-year contracts for 1.0 Bcf/d of firm capacity (increasing to 1.5 Bcf/d by 2015 and 1.7 Bcf/d by 2017) at $0.23/MMBtu, coupled with sales to buyers with firm transportation, should continue to insulate RRC’s gas from local price weakness during non-winter months.

Super Rich Wells Continue Tracking Curve

After 240 days online, 17 super-rich Marcellus wells continue to track the company’s 1.8 MMboe (10.9 Bcfe) type curve (up 43% from 1.3 MMBoe).

SWPA in GIP Bull’s-Eye

RRC latest investor presentation includes maps of the northern Appalachian Basin that show southwestern PA has the greatest gas-in-place (GIP) in the region within the Upper Devonian, Marcellus, and Utica/Point Pleasant.

Miss Lime Results Rebound

After 28 Miss Lime wells completed with smaller fracs during 1H13 yielded a disappointing 30-day average IP rate of 346 Boe/d (76% liquids) (21% below our 580 MBoe type curve), four wells completed in 3Q13 with larger fracs had a 65-day average rate 45% above the company’s 600 MBoe curve. A 12-mile northern step-out well had a 30-day average rate of 330 Boe/d (below our curve but greater liquids 85% vs 77%).

Positive Release

The release is generally positive as RRC posted another strong quarterly beat, although natural gas price concerns are likely to continue to weigh on the stock despite the company’s strong execution and immense resource base.

Baird Energy Daily Dirt – 10.30.13

RRC 3Q13 initial read: EPS beat but ops update largely neutral; stock reaction likely muted (Peng). Adjusted 3Q13 EPS/DCFPS of $0.35/$1.51 were ahead of our $0.27/$1.36 and consensus $0.30/$1.39. The beat was driven largely by lower costs. 2013 production guidance reaffirmed at the high end of the range and capex maintained. Solid execution continues; super-rich wells with RCS reported impressive IP of 2,657 boe/d; additional firm contracts to align takeaway capacity with anticipated production growth. We maintain our Outperform rating with a thesis predicated on Range’s solid execution and vast resource potential anchored by a premier core acreage position in the low-cost Marcellus.

Wells Fargo Securities Note – 10.30.13

Summary – Positive. Adjusted EPS of $0.35 beat consensus’ $0.30 and our $0.26 estimate. Street should like increased takeaway commitment, rhetoric around pricing, and new Gas in Place (GIP) resource maps. RRC’s pre-release provided pricing realizations and production results; so nothing unexpected on those fronts.

Marcellus: Firm Capacity Increased, Pricing Detailed, GIP Maps. RRC’s increased its firm capacity to 1.0 Bcfe/d, which increases to 1.5 Bcfe/d in 2015. This is up meaningfully from prior levels of ~ 700 Mcfe/d and 920 Mcfe/d. In addition to the firm capacity, RRC also has firm sales contracts over the next 12-24 months of 300 MMcfe/d. On the pricing front, RRC stated that if its future ethane agreements were in place today, its ethane price would be equal to a natural gas price of $4.13, which would add $0.40-0.50/Mcfe to an equivalent natural gas price. Further, its Q3 realizations for all of its Marcellus natural gas production was only $0.06 below NYMEX, which is better than we had expected prior to pre-release. Finally, in its presentation, RRC provided Gas in Place (GIP) maps the Marcellus, Upper Devonian, and Utica, with the largest stacked pay resource located on top of RRC’s acreage in Southwestern PA.

Production/Operations. Company now targeting 196 planned wells to sales in 2013 (Marcellus and Hz Miss), up from 173 prior with the increase in the Super-Rich area. Super rich wells brought on line average 13 Bcfe/d, as rates have trended higher with new completion techniques. Previously completed super-rich wells trending 43% above the 1.32 Mboe type curve. In the Mississipian, step-out well drilled in the northern part of its acreage was successful (previous focus had been in southern part). In addition, RRC has returned to large fracs and those wells “significantly exceed” wells drilled with smaller fracs, with the larger frac wells tracking 45% above the 600 Mboe type curve over the first 60 days.

Q4 Guidance. Management already pointed towards the high-end of its 20-25% 2013 production growth target, but today’s (10/29) release did include sequential declines in guidance for several operating expenses (opex). Direct opex guidance declined to $0.35/Mcfe (mid-point) compared to Q3 guidance of $0.39/Mcfe. Transportation ($0.78/Mcfe) and interest expense ($0.50/Mcfe) also declined.

SunTrust Robinson Humphrey Note – 10.30.13

3Q13 Earnings Recap

Earnings better than expected after previously announcing production/realized prices as unit costs continue to fall; we expect RRC shares to trade higher on the solid production growth including a recent new super-rich Marcellus 24hr-IP of 5,720 Boe/d (63%).

  • Recurring EPS of $0.36 vs STRH $0.39e and Street $0.30e
  • Production of 960 mmcfed vs STRH 951e, Street 952e
  • Production was 77% natural gas, 16% natural gas liquids (“NGLs”) and 7% crude oil and condensate.
  • 3Q realized average price of $4.80/Mcf slightly lower than STRH $5.05e lower than prior quarter $5.02 and Street $4.95e.

Guidance

Though not specific guidance given, RRC stated that 2013 sequential production should hit the higher end of the 20%-25% expected range. More importantly, the sizable position in the Marcellus Shale gives confidence of similar line-of-sight growth of 20%-25% for many years.”

Operational Highlights

  • Best super-rich Marcellus well announced this quarter in Washington County PA reported 24hr-IP of 5,720 Boe/d (63% liquids).
  • 23 new super-rich Marcellus wells in SW PA with 2,122 Boe/d average (66% liquids).
  • 10 new NW PA wells online in Lycoming County. One step out well in area had 24hr-IP of 19.7 Mmcf/d.
  • 7 new Hz Ms with larger fracs had average of 622 Boe/d (75% liquids).
  • 6 new vertical Wolfberry wells with 24hr-IP average of 243 Boe/d (77% liquids).
  • Mariner West fully operational in next month.

Capital One Morning Energy Summary – 10.30.13

Slightly positive. RRC reported strong initial results on Marcellus wells utilizing the new design that includes longer laterals/more frac stages. RRC posted a 3Q EPS/CFPS beat vs the Street, and it secured a significant amount of firm transportation at what we think is a reasonable cost. 3Q EPS was 35c vs 30c/28c Street/COS. 3Q CFPS was $1.51 vs $1.40/$1.37 Street/COS. The beat vs our model was primarily driven by all-in unit costs that were 6% below our forecast. As usual, no surprises on production or pricing given the pre-announcements (production of 960 MMcfe/d was 1% above consensus at the time of pre-announcement). RRC still expects FY13 production growth to be at the high end of its previously guided 20% – 25% y/y range. 4Q13 production is guided at ~1.0 Bcfe/d with 25% liquids, which is close to the Street’s 1.02 Bcfe/d est and the mix would compare favorably to the 21% – 23% liquids cut reported in the first 3 quarters of 2013. RRC’s 3Q CAPEX totaled ~$340MM, and mgmt reaffirmed its FY13 CAPEX of $1.3B. RRC currently has ~1.0 Bcf/d of firm capacity arrangements (up from ~0.8 Bcf/d reported in 2Q), and this increases to ~1.5 Bcf/d by 2015 (a sizable increase from the 0.9 Bcf/d in 2015 reported in 2Q). Management has thus made significant progress layering in firm capacity in the last few months, and the $0.20 – 0.25/Mcf cost reported for the incremental capacity looks to be in line with the weighted average cost of $0.23/Mcf for RRC’s total 1.5 Bcf/d of firm capacity for 2015. Mgmt intends to layer in add’l firm commitments as it grows production, which the company still expects to increase 20% – 25% y/y for “many years.” We expect that a large focus of the call will be devoted to the outlook for Marcellus gas differentials. In northern Marcellus, a step-out well in Lycoming County was brought online in 3Q at a 22.9 MMcf/d IP. Two add’l wells on the same pad were turned to sales under constrained conditions at a combined rate of 42 MMcf/d. The three wells had an avg lateral length of 5,000’ and 23 frac stages vs the previous well design of 3,500’ laterals/18 frac stages.

Important disclosures: The information provided herein is believed to be reliable; however, EnerCom, Inc. makes no representation or warranty as to its completeness or accuracy. EnerCom’s conclusions are based upon information gathered from sources deemed to be reliable. This note is not intended as an offer or solicitation for the purchase or sale of any security or financial instrument of any company mentioned in this note. This note was prepared for general circulation and does not provide investment recommendations specific to individual investors. All readers of the note must make their own investment decisions based upon their specific investment objectives and financial situation utilizing their own financial advisors as they deem necessary. Investors should consider a company’s entire financial and operational structure in making any investment decisions. Past performance of any company discussed in this note should not be taken as an indication or guarantee of future results. EnerCom is a multi-disciplined management consulting services firm that regularly intends to seek business, or currently may be undertaking business, with companies covered on Oil & Gas 360®, and thereby seeks to receive compensation from these companies for its services. In addition, EnerCom, or its principals or employees, may have an economic interest in any of these companies. As a result, readers of EnerCom’s Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this note. The company or companies covered in this note did not review the note prior to publication. EnerCom, or its principals or employees, may have an economic interest in any of the companies covered in this report or on Oil & Gas 360®. As a result, readers of EnerCom’s reports or Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this report.


Important disclosures: The information provided herein is believed to be reliable; however, EnerCom, Inc. makes no representation or warranty as to its completeness or accuracy. EnerCom’s conclusions are based upon information gathered from sources deemed to be reliable. This note is not intended as an offer or solicitation for the purchase or sale of any security or financial instrument of any company mentioned in this note. This note was prepared for general circulation and does not provide investment recommendations specific to individual investors. All readers of the note must make their own investment decisions based upon their specific investment objectives and financial situation utilizing their own financial advisors as they deem necessary. Investors should consider a company’s entire financial and operational structure in making any investment decisions. Past performance of any company discussed in this note should not be taken as an indication or guarantee of future results. EnerCom is a multi-disciplined management consulting services firm that regularly intends to seek business, or currently may be undertaking business, with companies covered on Oil & Gas 360®, and thereby seeks to receive compensation from these companies for its services. In addition, EnerCom, or its principals or employees, may have an economic interest in any of these companies. As a result, readers of EnerCom’s Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this note. EnerCom, or its principals or employees, may have an economic interest in any of the companies covered in this report or on Oil & Gas 360®. As a result, readers of EnerCom’s reports or Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this report.