RANGE RESOURCES CORPORATION (NYSE: RRC) today announced its third quarter 2014 financial results.

Third Quarter Highlights –

  • Range produced a record average of 1,209 Mmcfe per day, an increase of 26% over the prior year quarter
  • Unit costs decreased $0.36 per mcfe or 10% compared to the prior year quarter
  • Outstanding well results continue in the Marcellus
  • New technology in Nora field yields best results in years with returns up to 100%
  • 45 new gas purchase customers added to date in 2014
  • New bank agreement announced with a maximum facility amount of $4.0 billion and reduced borrowing costs
  • Credit upgrades announced from Standard and Poor’s and Moody’s

Commenting on the results, Jeff Ventura, Range’s President and CEO, said, “Range set a record production level this quarter of over 1.2 Bcfe per day net to Range, driven by the Marcellus. It is exciting to see how far we have come since Range completed the Marcellus discovery well ten years ago this month. We are even more excited about future growth, as we capitalize on the first mover advantages Range enjoys in the Marcellus. This includes the largest net acreage position in Pennsylvania, specifically in southwest Pennsylvania, where we have leased the core of the highest hydrocarbon in place in the basin when considering stacked pay potential in the Marcellus, Utica and Upper Devonian. This also is the area that has the liquids-rich portion of the Marcellus and Upper Devonian. We have secured the lowest cost firm transportation portfolio of our peers which aligns with our production growth target of 20% to 25% per year. As these transportation contracts come into service, they will move an increasing portion of our natural gas and natural gas liquids to markets with strong year-round demand and stable index prices.”

“Although the rapid growth in Marcellus production has created a challenging regional pricing environment for this quarter, looking ahead, prices are expected to improve. In addition, our liquids pricing, net of transportation costs, will be enhanced with the start-up of Mariner East. The propane portion is projected to start in early 2015 and the ethane portion in July 2015. We believe that as midstream projects come on line in 2015 and beyond, designed to move Marcellus gas to new markets with increasing levels of demand, the current supply/demand imbalance in the Appalachian basin will improve. As a first mover, with a low cost structure, strong balance sheet and a proven track record, Range is well-positioned to continue our annual 20% to 25% production growth to 3 Bcfe per day and beyond.”

Operational Discussion

Range has updated its investor presentation. Please see www.rangeresources.com under the Investor Relations tab, “Presentations and Webcasts” area, for the presentation entitled, “Company Presentation – October 29, 2014.”

Range produced a record average of 1,209 Mmcfe per day during the third quarter, consisting of 822.4 Mmcf per day of gas, 53,640 barrels of NGLs and 10,710 barrels per day of oil and condensate. Third quarter 2014 production exceeded the prior year quarter by 26% and the previous quarter by 9.4%. Production guidance for the fourth quarter is 1,350 Mmcfe per day, with 30% liquids. Annual production growth beyond 2014 is expected to be in the range of 20% to 25%.

Southern Marcellus Shale Division –

Production for the third quarter averaged 943 (778 net) Mmcfe per day for the division, a 36% increase over the prior year. The division’s third quarter net production included 431 Mmcf per day of gas, 49,423 barrels per day of NGLs and 8,531 barrels per day of condensate.

During the third quarter, the division brought on line 28 wells in southwest Pennsylvania, with 19 wells in the super-rich area, six wells in the wet area and three wells in the dry area. The per well average 24-hour initial production rate (“IP”) for the new wells averaged 15.9 (12.3 net) Mmcfe per day, (7.8 Mmcf per day of gas, 977 barrels per day of NGLs and 363 barrels per day of condensate), with an average lateral length of 4,660 feet with 24 stages.

In the wet and super-rich areas, the Company continued to drill and complete outstanding wells. In the super-rich area, one five well pad tested at an average 24-hour IP per well of 2,472 (2,302 net) boe per day with 71% liquids, or 14.8 Mmcfe per day (872 barrels of condensate, 876 barrels of NGLs and 4.3 Mmcf gas per day). The average per well lateral length was 4,225 feet with 21 stages. Another four well pad in the super rich area was brought on line at a per well average 24-hour IP of 2,850 (2,367 net) boe per day with 52% liquids, or 17.1 Mmcfe per day (513 barrels of condensate, 1,323 barrels of NGLs and 8.3 Mmcf gas per day). The average lateral length per well was 4,886 feet with 25 stages. In the wet area, a six well pad came on line at an average 24-hour IP per well of 16.5 (13.5 net) Mmcfe per day with 53% liquids (7.7 Mmcf of gas, 41 barrels of condensate and 1,423 barrel of NGLs per day). The average lateral length was 4,301 feet with 22 stages.

The division brought on line three wells in the dry gas area for the quarter. The per well average 24-hour IP per stage of the wells brought on line in the dry gas area was almost 1 Mmcfe per day per stage or a per well average 24-hour IP of 26.4 Mmcfe per day per well, with an average lateral length of 5,364 feet and 28 frac stages.

Range expects to turn to sales a total of 38 wells in the Southern Marcellus during the fourth quarter of 2014. Capital efficiencies have continued to improve, with several factors contributing to the improvement. Range will drill approximately 12% of its Marcellus wells in 2014 on existing pads, where it expects to benefit from improved landing target selection and completion techniques while at the same time avoiding the estimated cost of $850,000 for building a new pad and road at each location. Drilling efficiencies are continuing with Marcellus cost per lateral foot drilled decreasing by 15% in 2014 from $553 per lateral foot to $472 per lateral foot. The number of frac stages completed in 2014 has increased 55% compared to 2013. The Company is also expected to realize additional savings from optimizing existing gathering and compression infrastructure during production. For 2015, the average planned horizontal lateral will be 6,200 feet.

The Company recently set pipe on its initial dry gas Utica/Point Pleasant test in Washington County, Pennsylvania, the Claysville Sportsman’s Club #1. The well is targeted to be completed with 32 frac stages using a reduced cluster spacing completion. The well was drilled from an existing Marcellus pad. Range will be conducting several scientific tests with extensive data collection on this well and anticipates that initial production results will be available in late December.

Northern Marcellus Shale Division –

In northeast Pennsylvania, production for the third quarter averaged 269 (228 net) Mmcfe per day for the division, a 25% increase over the prior year. During the third quarter, Range drilled six wells and turned seven wells to sales and is expecting to turn an additional seven wells to sales in the fourth quarter.

Production from a four well pad brought on line in the third quarter had a per well average 24-hour IP of 19.8 Mmcf per day. After 27 days on line, the wells produced at an average per well of 14.8 Mmcf per day. These four wells were drilled with an average lateral length of 4,885 feet and 25 frac stages. Lateral lengths and number of frac stages are expected to increase going forward, with laterals approaching 6,000 feet with 30 frac stages planned in 2015.

Midcontinent Division –

Production for the third quarter averaged 86 net Mmcfe per day for the division, a 9% decrease from the prior year. The division’s third quarter net production included 49.2 Mmcf per day of gas, 4,106 barrels per day of NGLs and 2,011 barrels per day of oil.

During the third quarter, the Midcontinent division continued to evaluate results from geological modeling in the Mississippian Chat along the Nemaha ridge. Results are encouraging, as the last two quarters had the two highest average 24-hour IP rates achieved to date. The five wells brought on line in the third quarter averaged a per well 24-hour IP rate of 661 (534 net) boe per day with 72% liquids. The five wells had an average lateral length of 3,722 feet with 19 frac stages.

The second highest oil rate well this year came on line this quarter at a 24-hour IP of 1,165 (941 net) boe per day with 84% liquids (763 barrels oil, 210 barrels NGLs and 1,148 mcf gas per day). The highest oil rate well, announced in the previous quarter, had a 24-hour IP of 1,263 boe per day with 92% liquids (1,062 barrels oil, 98 barrels NGLs and 618 mcf gas per day). This highest oil rate well continues to perform well, averaging 877 boe per day with 88% liquids (679 barrels oil, 97 barrels NGLs and 606 mcf gas per day) for the first 30 days.

The division brought on line a St. Louis well in the third quarter that tested at a 24-hour peak rate of 9.6 (6.5 net) Mmcfe per day comprised of 6.1 Mmcfe gas, 286 barrels oil and 301 barrels NGLs per day. Year to date, six St. Louis wells have been brought on line, with a total 24-hour IP of 41.8 (22.8 net) Mmcfe per day total, with 34% liquids.

For the fourth quarter of 2014, the Company expects to bring on line three Mississippian Chat wells and one additional well in the Texas Panhandle.

Southern Appalachia Division –

Production for the third quarter averaged 113 (110 net) Mmcf per day for the division, a 52% increase over the prior year. The acquisition of EQT’s 50% interest added approximately 40 Mmcf per day to third quarter production, compared to the second quarter of 2014.

Range had a full quarter of operational control over the Nora assets in Virginia during the third quarter after acquiring the remaining 50% working interest in the field and gathering system from EQT at the end of the second quarter 2014. In this short period of time, Range has already achieved some of the best results to date by utilizing a new well design coupled with a higher rate stimulation technique on both vertical coal bed methane (CBM) and vertical tight gas wells. With six wells turned to sales using this new design, CBM results are 100% better than the historical field average, with a modest increase of approximately $15,000 per well. Of particular note, one CBM well is producing at five times the average CBM well rate and early results indicate that it is the best CBM well drilled in the Nora field in 15 years.

Similar improvements have been achieved with the new designs on vertical tight gas wells, with results 70% better than the field average, with a cost increase of approximately $12,000 per well. With seven tight gas wells turned to sales using this new technique, the 30-day well production average of these wells is the highest in over 10 years.

In the third quarter, the division turned to sales seven tight gas wells, two CBM wells and one horizontal Huron shale well. Fourth quarter plans include bringing on line 10 additional tight gas wells, 14 CBM wells, three horizontal Huron wells and performing recompletions and workovers on 10 CBM wells. Continued expansion in Virginia will utilize the 130 Mmcf per day of current existing capacity within the Nora gathering system. Gas markets remain strong in the Southeast with Range receiving approximately $0.20 above NYMEX for production from the Nora field.

Marcellus Shale Marketing, Transportation and Processing Update –

In the early stages of the Marcellus play, Range anticipated that successful development would inevitably create a regional oversupply beyond what local demand could absorb. At that time, Range began focusing its marketing efforts on developing new markets outside the Appalachian basin, along with securing transportation arrangements at a reasonable cost to serve these markets. As a result, Range anticipates having the capability of selling Appalachian gas to a customer base that stretches from the Northeast to the Upper Midwest, the Gulf Coast and Texas, Florida and the Atlantic Coast. To this end, the Company has added 45 new natural gas customers so far in 2014. This has allowed Range to diversify its natural gas pricing, as we expect to move gas to over 20 different indices by 2018. Accordingly, the Company expects its Marcellus price realizations to improve in the years ahead compared to prices being received in Appalachia today, given the almost 34 Bcf per day of announced Appalachian basin pipeline takeaway projects that are expected to be in service by the end of 2018. Range expects that long-term differentials in Appalachia will ultimately equal the cost of transport out of the basin.

At the end of the third quarter, Range has contracts in place for approximately 1.1 Bcf per day of transportation capacity, increasing to 2.4 Bcf per day by 2018. Range’s objective has been to layer in additional commitments that follow the Company’s growing production volumes. These future capacity additions, to multiple markets outside the Appalachian region, will support Range’s growth while maximizing net realized gas prices. As a result of discovering the Marcellus and being a first mover in securing transportation, Range has been able to secure its firm transportation and firm sales through 2016 at an expected average cost of $0.28 per Mmbtu in 2016, rising to $0.39 through 2018. Range expects that costs can be further reduced with our contractual marketing arrangements. Importantly, the Company has the option to renew many of these transportation agreements at the currently contracted rate.

Range is the largest producer of wet gas and NGLs in the Appalachian basin, with the most comprehensive and diversified plan to move our growing volumes of gas, NGLs and condensate. Similar to the Company’s natural gas diversification strategy, its existing NGL contracts and commitments are intended to ensure Range can move all products to new and growing markets at prices greater than what would alternatively be realized in local markets. The Mariner East project provides Range benefits on propane and ethane. In early 2015, the propane portion of Mariner East is expected to be operational, allowing Range to continue selling propane to international markets, but at significantly lower transportation cost to Sunoco’s Marcus Hook facility in Philadelphia. The project also adds size and scale, opening up the potential for other marketing options. Mariner East is expected to further diversify and strengthen Range’s ethane marketing abilities when it becomes operational in July 2015 by selling ethane to INEOS for use in its European petrochemical facilities.

Range has recently posted a presentation to our website entitled “Takeaway Capacity in Appalachia” that explains many of the macro dynamics that have occurred in the Appalachian basin due to the rapid growth of Marcellus production, the outlook for the future and Range’s strategy regarding the current and future challenges.

Financial Discussion

(Except for generally accepted accounting principles (“GAAP”) reported amounts, specific expense categories exclude non-cash impairments, unrealized mark-to-market on derivatives, non-cash stock compensation and other items shown separately on the attached tables. “Unit costs” as used in this release are composed of direct operating, transportation, gathering and compression, production and ad valorem tax, general and administrative, interest and depletion, depreciation and amortization costs divided by production. See “Non-GAAP Financial Measures” for a definition of each of the non-GAAP financial measures and the tables that reconcile each of the non-GAAP measures to their most directly comparable GAAP financial measure.)

GAAP revenues for the third quarter of 2014 totaled $617 million (39% increase as compared to third quarter 2013), GAAP net cash provided from operating activities including changes in working capital was $213 million versus $223 million in the third quarter 2013 and GAAP earnings were $146 million ($0.86 per diluted share) versus net income of $19 million ($0.12 per diluted share) in the third quarter 2013, an increase of 663%.

Several non-cash or non-recurring items impacted third quarter results. A $125 million favorable non-cash mark-to-market gain on derivatives, a $46 million mark-to-market gain due to the decrease in value of the Company’s common stock held in the Company deferred compensation plan (which was fully funded on the date of grant), $13.4 million for abandonment and impairment of unproved properties, a $4.9 million fine for water handling and storage issues and $14 million of non-cash stock compensation expenses were recorded.

Non-GAAP revenues for third quarter 2014 totaled $491 million (13% increase as compared to third quarter 2013), cash flow from operations before changes in working capital, a non-GAAP measure (“adjusted cash flow”), reached $257 million (a 5% increase as compared to third quarter 2013). Adjusted net income, a non-GAAP measure, for third quarter 2014 was $62 million (an 8% increase as compared to third quarter 2013).

Total unit costs improved by $0.36 per mcfe or 10% compared to the prior-year quarter, with the largest decreases in interest expense, production and ad valorem taxes and depreciation, depletion and amortization expense.

Third quarter production volumes averaged 1,209 Mmcfe per day, a 26% increase over the prior-year quarter. Year-over-year gas production increased 11%, NGL production rose 109%, while oil and condensate production was down 3%, primarily due to the Conger property exchange in late second quarter, representing approximately 9% of oil and condensate volumes for the quarter. The third quarter 2014 natural gas, NGLs and oil price realizations (including the impact of cash-settled hedges and derivative settlements which would correspond to analysts’ estimates, a non-GAAP measure) averaged $4.16 per mcfe, a 13% decrease over the prior-year quarter of $4.80 per mcfe, partially due to the Conger exchange in second quarter 2014.

  • Production and realized prices after hedging for each commodity for the third quarter of 2014 were: natural gas — 822 Mmcf per day ($3.63 per mcf), NGLs — 53,640 barrels per day ($22.53 per barrel) and crude oil and condensate — 10,710 barrels per day ($78.66 per barrel).
  • The third quarter average natural gas realized price before hedging settlements was $3.34. Financial hedges based upon NYMEX increased realizations by $0.06 per mcf while financial basis hedges increased realizations by $0.22 per mcf during the quarter. The average Company natural gas differential including the settled financial basis hedges but before NYMEX hedging for the third quarter was $(0.49) per mcf compared to $(0.58) per mcf for the second quarter 2014. (See the schedule below which details the components of the non-GAAP average realized natural gas price for the quarter and the tables presented elsewhere that reconcile the non-GAAP measures to their most directly comparable GAAP financial measure.)
  • NGL pricing before the impact of hedging was 23% of WTI or $22.26 per barrel for the third quarter of 2014 ($22.53 per barrel after hedging, hedging added $0.27 per barrel). Ethane was approximately 50% of the total composite barrel in the Marcellus during the quarter.
  • Crude oil and condensate price realizations, before financial hedges, for the third quarter averaged 84% of WTI or $81.34 per barrel ($78.66 per barrel after hedging, hedging reduced realizations by $2.68 per barrel).

Range is one of the few producers in the Appalachian basin currently extracting ethane. Importantly, due to the favorable pricing reflected in Range’s existing and unique ethane contracts, ethane extraction increases cash flow, as shown in the tables below, compared to leaving ethane in the gas stream and being paid for the increased Btu content of the gas (ethane rejection). As ethane extraction increases our cash flow, it will also increase NGL volumes, but will decrease the average price for both natural gas and NGLs, which should be considered when comparing Range’s price realizations versus producers who reject ethane.

Range Resources SW Marcellus – Third Quarter 2014
3Q Pro-forma 3Q Actual 3Q Pro-forma
3Q 2014 assuming no ethane recovery Transportation and processing costs shown as separate expense rather than deduct to NGL price 3Q 2014 assuming full ethane recovery and utilization of all three ethane and propane projects
Gross Revenue, pre-hedge
Natural gas (per mcf) $ 3.64 $ 3.49 $ 3.47
Natural gas liquids (per bbl) 44.25 29.71 30.73
Condensate (per bbl) 78.04 78.04 78.04
Total revenue (per mcfe) 5.23 4.67 4.76
Operating Expenses (per mcfe)
Direct operating 0.25 0.21 0.21
Transport, gathering & processing * 1.71 1.47 1.46
Production tax (impact fee) 0.09 0.08 0.08
Cash Production Cost 2.05 1.76 1.75
Cash Production Margin (per mcfe) $ 3.18 $ 2.91 $ 3.01
Cash Flow (millions) $ 196 $ 208 $ 223
* Includes expense associated with ethane and propane transportation agreements, such as ATEX or Mariner East. For this illustration, NGL processing fees, and truck and rail expenses are also included as an expense rather than a reduction to NGL price, as would be typical for GAAP purposes.

Range expects that with the propane and ethane volumes being shipped on Mariner East in 2015, the incremental uplift in cash flow will reach $100 million on an annualized basis.

New Bank Agreement Signed and Credit Ratings Upgraded

Subsequent to the end of the quarter, Range announced that it amended and restated its revolving credit facility. The new five-year agreement has a maximum facility size of $4 billion, with an initial borrowing base of $3 billion and $2 billion in commitments. This represents an increase in the borrowing base of $1 billion and increased commitments of $250 million. The agreement also reduces drawn borrowing costs by 25 basis points and grants Range the option to release all collateral upon the receipt of a single investment grade rating. The maturity date is extended to October 16, 2019. On October 16, Standard & Poor’s Ratings Services announced it had upgraded Range’s corporate credit rating to BB+. Earlier in September, Moody’s Investors Service upgraded Range’s outlook to ‘Positive’ with a current corporate rating of Ba1.

Capital Expenditures

Third quarter drilling expenditures of $341 million funded the drilling of 71 (68 net) wells and the completion of previously drilled wells. A 100% drilling success rate was achieved. In addition, during the third quarter, $36 million was expended on acreage, $6 million on gas gathering systems and $10 million for exploration expense. Range is on track with its 2014 capital expenditure budget of $1.52 billion.

Guidance – Fourth Quarter 2014

Production Guidance:

Production growth for 2014 is targeted at 25% year-over-year. Average daily production for the fourth quarter is expected to be approximately 1.35 Bcfe per day, with 30% liquids.

Guidance for 2014 Activity:

Under the current plan, which is still subject to change, Range expects to turn to sales approximately 76 wells during the fourth quarter in the Marcellus, Nora and Midcontinent, as shown below:

Total Wells to Sales YTD Expected Remaining Wells to Sales in 4Q 2014 Planned Total Wells to Sales in 2014
Super-Rich area 44 13 57
Wet area 24 21 45
Dry area-SW 9 4 13
Dry area-NE 13 7 20
Total Marcellus 90 45 135
Nora area 19 27 46
Midcontinent 19 4 23
Total 128 76 204

4Q 2014 Expense per mcfe Guidance:

Direct operating expense $0.29 – $0.32 per mcfe
Transportation, gathering and compression expense $0.76 – $0.78 per mcfe
Production tax expense $0.11 – $0.13 per mcfe
Exploration expense $26 – $29 million
Unproved property impairment expense $15 – $18 million
G&A expense $0.33 – $0.35 per mcfe
Interest expense $0.30 – $0.33 per mcfe
DD&A expense $1.28 – $1.30 per mcfe

Non-GAAP Natural Gas Price Realizations and Differentials

Range continues to hedge a significant portion of its estimated future production in order to lock in prices and returns which provide certainty of cash flow to execute our capital plans. During the third quarter, most Appalachian price indices continued to weaken as additional supply growth outpaced regional demand and infrastructure to export natural gas out of the basin. Range offset some of this regional weakness by hedging basis, as reflected in the $0.22 gain per mcf on basis hedging in the third quarter, resulting in a corporate differential of $0.49 below NYMEX. Range has hedged Marcellus and other basis for 370,000 Mmbtu per day for October 2014, 95,000 Mmbtu per day from November 2014 through March 2015, and 5,000 Mmbtu per day for April 2015 through October 2015. The fair value of the basis hedges based upon future strip prices as of September 30, 2014 was a gain of $12.7 million for the fourth quarter 2014, a loss of $14.3 million for first quarter 2015 and a gain of $120,000 for the remainder of 2015. The table below shows the components of the non-GAAP measure of “average natural gas realized prices” for the last five quarters for comparative purposes as it would be calculated by analysts. A similar analysis is shown on the Company’s website for NGLs and condensate and crude oil.

Corporate Differential Disclosure 3Q 2013 4Q 2013 1Q 2014 2Q 2014 3Q 2014
NYMEX Index average price $3.60 $3.62 $4.92 $4.67 $4.05
Differential under GAAP reporting (1) ($0.17) ($0.22) $0.66 ($0.60) ($0.71)
Cash settled basis hedging $0.00 ($0.01) ($0.90) $0.02 $0.22
Differential including basis hedging ($0.17) ($0.23) ($0.24) ($0.58) ($0.49)
Average price before NYMEX hedges $3.43 $3.39 $4.68 $4.09 $3.56
Cash settled NYMEX hedges $0.45 $0.45 ($0.49) ($0.21) $0.07
Average price including all hedges $3.88 $3.84 $4.19 $3.88 $3.63
(1) Midcontinent Division realized sales prices contain certain processing and gathering charges, resulting in an approximately $0.60 negative effect on the GAAP reported differential for the division

Basis Differentials:

Based upon the contracts that Range has in place for the periods disclosed and the future basis differential indications from quotations on ICE (the “Intercontinental Exchange”) as of October 24, 2014, the calculated differential in each division would be the amounts shown in the table below. Basis at the various receipt points which we sell natural gas are inherently volatile, have wide spreads between the bid and ask indications and change on a daily basis. The table below represents the Company’s calculated differentials at a point in time (October 24, 2014), not an expected future realized price. The percentages of expected production to be sold by indices are shown in the corporate presentation posted on the website and should be used along with the table below in modeling the expected differentials by division adjusted for the weighted average change in the indices from October 24, 2014 to the measurement date for each month. For comparative purposes, a table of historical basis settlements and actual differentials by division is included in Table 9 of the Supplemental Tables for third quarter 2014 on the Company’s website.

Calculated Estimates by Division
Actual 3Q 2014 4Q 2014 1Q 2015
Based on NYMEX
SW PA $ (0.56 ) $ (0.55 ) $ + 0.25
NE PA (1.44 ) (1.57 ) (1.20 )
Nora + 0.25 + 0.20 + 0.20
Midcontinent (1) (0.76 ) (0.80 ) (0.80 )
Basis Hedging + 0.22 + 0.17 (0.12 )
Corporate Differential $ (0.49 ) $ (0.58 ) $ (0.31 )
(1) Midcontinent processing, gathering and transportation costs are netted against the realized price received from a third party which increases the differential by approximately $0.60.

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