UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of
the Securities Exchange Act of 1934
Date of report (Date of earliest event reported): April 30, 2014 (April 28, 2014)
RANGE RESOURCES CORPORATION
(Exact name of registrant as specified in its charter)
| Delaware | 001-12209 | 34-1312571 | ||
| (State or other jurisdiction of incorporation) |
(Commission File Number) |
(IRS Employer Identification No.) |
| 100 Throckmorton, Suite 1200 Ft. Worth, Texas |
76102 | |
| (Address of principal executive offices) | (Zip Code) |
Registrant’s telephone number, including area code: (817) 870-2601
(Former name or former address, if changed since last report): Not applicable
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligations of the registrant under any of the following provisions (see General Instruction A.2. below):
| ¨ | Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
| ¨ | Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |
| ¨ | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
| ¨ | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
| ITEM 2.02 | Results of Operations and Financial Condition |
On April 28, 2014 Range Resources Corporation issued a press release announcing its first quarter 2014 results. A copy of this press release is being furnished as an exhibit to this report on Form 8-K.
ITEM 9.01 Financial Statements and Exhibits
(d) Exhibits:
| 99.1 | Press Release dated April 28, 2014 |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| RANGE RESOURCES CORPORATION | ||
| By: | /s/ Roger S. Manny | |
| Roger S. Manny Chief Financial Officer | ||
Date: April 30, 2014
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EXHIBIT INDEX
| Exhibit Number |
Description | |
| 99.1 | Press Release dated April 28, 2014 | |
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EXHIBIT 99.1
RANGE ANNOUNCES FIRST QUARTER 2014 RESULTS
FORT WORTH, TEXAS, APRIL 28, 2014…RANGE RESOURCES CORPORATION (NYSE: RRC) today announced its first quarter 2014 financial results.
First Quarter Highlights –
| • | Production volumes reached a record high, averaging 1,056 Mmcfe per day, a 21% increase over the prior-year quarter |
| • | Adjusted cash flow reached $262 million, an increase of 20% compared to the prior-year quarter |
| • | Unit costs per mcfe declined 6% compared to the prior-year |
| • | Reported net income of $33 million for the quarter compared to a net loss of $76 million in the prior-year quarter |
| • | Marcellus super-rich well tested at 24-hour rate of 6,357 boe per day, or 38.1 Mmcfe per day (65% liquids), with a 7,065 foot lateral and 36 frac stages. This is the highest rate Marcellus well in the southwest portion of the play drilled to date by any operator |
| • | Mississippian Chat well tested at 24-hour rate of 1,263 boe per day at 92% liquids, the highest oil rate (1,062 barrels per day) of any Range well to date |
Commenting on the announcement, Jeff Ventura, Range’s President and CEO, said, “Range continues to execute impressively in all areas of our business. Production grew 21% and adjusted cash flow increased 20%. During the first quarter, we drilled our two highest rate wells ever in the Marcellus Shale and Mississippian Chat plays, costs are continuing to decline and two of our three major ethane projects became fully operational. When the third ethane sales outlet, Mariner East, begins operations next year, our three ethane solutions combined are expected to provide a 25% uplift for our ethane revenue versus leaving ethane in the gas stream, net of all transportation costs and processing fees. Significantly, these projects, combined with our firm transportation and marketing arrangements for natural gas, should allow us to continue growing our production volumes at 20% to 25% for many years, with one of the lowest cost structures in the industry.”
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—April 28, 2014.”
Marcellus Shale Marketing, Transportation and Processing Update-
Range has focused its marketing efforts on developing new markets outside the Appalachian basin and expects to continue securing firm transportation arrangements to serve these markets. Range’s firm transportation strategy is designed to (i) secure transportation owned by Range or our customers at relatively low cost, (ii) permit uninterrupted flow of our production and (iii) allow Range to receive a fair price for our products.
To support this strategy, Range has diversified its natural gas pricing among ten different indices, with 85% to 90% of the 2014 expected volumes tied to currently favorable indices. Range has been able to diversify all aspects of the sales process, and not rely heavily on any one customer or transportation outlet. This strategy is also evidenced by our three ethane solutions, with two projects fully operational, and the final project, Mariner East, expected to be operational in 2015. Combined, they provide geographic diversity, with end markets for ethane in Canada, Europe and Mt. Belvieu. Pricing is also diversified, and when all three projects are operational, are expected to yield a 25% revenue increase for ethane, compared to leaving the ethane in the gas stream, net of all transportation and processing costs.
Range has focused its drilling activity and marketing efforts in southwest Pennsylvania, where there are five major interstate pipelines. These pipelines were built to bring gas north from Texas, Oklahoma, Louisiana, and other southern states to serve the population and industrial centers in the northeast. Over the next two years, these pipelines are expected to be re-engineered to become bi-directional. With bi-directional capability, gas should flow north during winter months when local demand is 25 to 30
Bcf per day, and flow southeast, south and west during non-winter months, when local demand is only 8 to10 Bcf per day. Range has secured firm transportation on many of these pipelines in order to move gas to more favorable markets during all but the coldest months. We developed 25 new customers in 2013 in new markets, and have established 14 new customers to date in 2014. Range has added three firm transportation arrangements delivering approximately 175 Mmcf of takeaway capacity starting in April 2014. A portion of this capacity will be released to other operators while Range builds production at these delivery points. In the interim, this unused capacity will add approximately $0.07 per mcfe to our transportation costs for the second and third quarters of 2014. In addition, we recently added additional firm transportation capacity for 2017 and 2018.
During the period from April 20 through April 27, MarkWest Liberty processing complexes at Houston, Pennsylvania and Majorsville, West Virginia were down for scheduled maintenance. All the planned maintenance and facility upgrades were successfully completed on time and both processing plants are back up and operational. These maintenance turnarounds were planned at this time in order to complete tie-ins to the Mariner West ethane pipeline to Sarnia for other customers, install upgraded equipment to debottleneck the Houston fractionator, interconnect separate systems, upgrade interconnections between the two complexes to more efficiently move gas between the two and complete tie-ins for the new Majorsville 200 million cubic feet per day expansion which will serve Range gas later in the second quarter.
This was the first scheduled turnaround and maintenance operation since the plant complexes were originally constructed and is expected to facilitate Range’s growth over the next several years. Range congratulates MarkWest on this exceptionally well-executed turnaround and sees this as a very positive continuing step in MarkWest supporting Range’s multi-year growth plans.
Southern Marcellus Shale Division –
Production for the first quarter averaged 800 (672 net) Mmcfe per day for the division, a 34% increase over the prior year. The division’s first quarter net production included 358 Mmcf per day of gas, 44,141 barrels per day of NGLs and 8,224 barrels per day of condensate.
During the first quarter, the division brought online 13 wells in southwest Pennsylvania, with four wells in the super-rich area, eight wells in the wet area and one well in the dry area. The initial production rates of the new wells averaged 16.8 (13.7 net) Mmcfe per day with 59% liquids, with an average lateral length of 4,300 feet.
During the quarter, the division brought online three wells on one super-rich pad with an additional two wells brought online in April. One of the last two completed wells on the pad had the highest 24-hour test rate of any Marcellus well Range has drilled to date. It is also the highest rate well drilled in the southwest portion of the Marcellus to date by any operator. The well tested at a 24-hour rate of 6,357 (5,213 net) boe per day with 65% liquids, or 38.1 Mmcfe per day, (1,356 barrels condensate, 2,781 barrels NGLs and 13.3 Mmcf gas per day). This well was drilled with a 7,065 foot lateral with 36 frac stages. Including this well, the average 24-hour test rate per well for the five wells on this pad was 4,773 (3,922 net) boe per day with 65% liquids, or 28.6 Mmcfe per day, (888 barrels condensate, 2,193 barrels NGLs and 10.1 Mmcf gas per day). The average lateral length for the five wells was 6,635 feet with 34 frac stages. Range has previously guided to average lateral lengths in the super-rich area of 5,300 feet for its 2014 program wells. However, as we have stated, Range expects to routinely test longer laterals each year as our drilling program expands.
Range is currently bringing on three dry gas wells in eastern Washington County. These wells were drilled with average lateral lengths of 4,768 feet and completed with 25 frac stages. All three of these wells appear capable of over 20 Mmcf per day when the full facilities are in place. The wells are currently online and cleaning up.
Range commenced drilling its first Utica test in western Washington County. Range expects to drill the well with a 6,500 foot lateral in the Point Pleasant and to complete it with 32 frac stages using the RCS completion design. This well is expected to be 1,500 to 2,000 feet deeper than the industry Utica tests southwest of our location. Range expects this Utica test to be located in the core of the area believed to have the highest gas in place. The release of production test results is expected to be available in the fourth quarter.
At the end of the first quarter, the division was operating nine rigs comprised of three air rigs and six horizontal rigs. Due to drilling efficiencies and the pace of planned activity for the remainder of the year, this is expected to be reduced to be three air rigs and three horizontal rigs by the end of the year. Range expects to turn to sales a total of 115 wells in the southern Marcellus during the remainder of 2014.
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Northern Marcellus Shale Division –
In northeast Pennsylvania, production for the first quarter averaged 232 (195 net) Mmcfe per day for the division, a 10% increase over the prior year. Range drilled three wells in the first quarter and turned one well to sales. The Company’s backlog of wells waiting on pipeline connection increased to nine at quarter-end. At the end of the quarter, Range had one drilling rig operating. Range anticipates drilling another 16 wells to meet its continuous drilling obligations under our large leases in the area and turning 13 wells to sales for the remainder of 2014.
Production from a four well pad mentioned in previous releases continues its strong performance. After 150 days, cumulative production from the four wells is over 7 Bcf, or a 150 day per well average of 11.8 Mmcf per day.
Midcontinent Division –
Production for the first quarter averaged 84.5 net Mmcfe per day for the division, an 11% increase over the prior year. The division’s first quarter net production included 51.2 Mmcf per day of gas, 3,395 barrels per day of NGLs and 2,160 barrels per day of oil.
During the first quarter, the Midcontinent division continued to focus on Range’s horizontal Mississippian Chat acreage along the Nemaha Ridge, and evaluate performance of recent wells completed using larger frac designs. A total of 5 (4.1 net) Mississippian Chat wells were turned to sales with average lateral lengths of 3,407 feet with 17 frac stages. Average 7-day rates for the completions were 457 (372 net) boe per day with 68% liquids. In addition, the division turned one St. Louis well to sales that had a 24-hour test rate of 11,431 (7,932 net) Mmcfe per day with 39% liquids (6,963 mcf gas, 408 barrels oil, and 337 barrels NGLs per day).
After the end of the first quarter, the division drilled a well with the highest oil rate of any Range Mississippian Chat well drilled to date. The well tested at a 24-hour rate of 1,263 boe per day with 92% liquids (1,062 barrels oil, 98 barrels NGLs and 618 mcf gas per day). Range continues to expect that its Mississippian Chat average EURs will fall within the 485 to 600 Mboe range.
Range expects to bring online 16 wells during the remainder of 2014. At quarter end, the division had three rigs operating.
Southern Appalachia Division –
The Southern Appalachia Division continued development of multi-pay horizons on its 360,000 (235,000 net) acre position in Virginia during the first quarter. Range owns the fee mineral on 216,000 net acres in Virginia and receives the added economic benefit of the royalty. The division had 1 rig running that drilled 3 (3 net) coalbed methane wells and also turned online 2 (2 net) coalbed methane wells. Production for the first quarter averaged 70 net Mmcfe per day for the division. The division plans to drill a mix of coalbed methane, tight gas and horizontal Huron Shale wells in 2014. The Virginia properties receive some of the highest gas prices in Appalachia and are strategically located to supply gas to the growing southeast markets.
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 first quarter of 2014 totaled $457 million (43% increase as compared to first quarter 2013), GAAP net cash provided from operating activities including changes in working capital reached $181 million (10% decrease as compared to first quarter 2013) and GAAP earnings were $33 million ($0.20 per diluted share) versus a net loss of $76 million ($0.47 loss per diluted share) in the first quarter 2013.
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Several non-cash or non-recurring items impacted first quarter results. A $42 million mark-to-market commodity hedge loss was recorded due the improvement in commodity prices. A $2 million mark-to-market expense recovery due to the decrease in the Company’s common stock held in the Company deferred compensation plan (which was fully funded on the date of grant), and $14 million of non-cash stock compensation expenses were recorded.
Non-GAAP revenues for first quarter 2014 totaled $501 million (19% increase as compared to first quarter 2013), cash flow from operations before changes in working capital, a non-GAAP measure (“adjusted cash flow”), reached $262 million (a 20% increase as compared to first quarter 2013). Adjusted net income, a non-GAAP measure, was $74 million (40% increase as compared to first quarter 2013) for the first quarter 2014.
Total unit costs decreased by $0.23 per mcfe or 6% compared to the prior-year quarter led by decreases in transportation, gathering and compression; general and administrative costs; interest expense and depreciation, depletion and amortization expense. These reductions more than offset the $0.03 per mcfe increase in operating expenses for the quarter.
First quarter production volumes reached a record high, averaging 1,056 Mmcfe per day, a 21% increase over the prior-year quarter despite Marcellus production being significantly impacted by the winter storms. Year-over-year oil and condensate production increased 13%, NGL production rose 137%, while natural gas production was flat. The first 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 $4.92 per mcfe, a 3% decrease over the prior-year quarter of $5.06 per mcfe, but a 3% increase over fourth quarter 2013 average price of $4.79 per mcfe.
| • | Production and realized prices after hedging for each commodity for the first quarter of 2014 were: natural gas – 689 Mmcf per day ($4.20 per mcf), NGLs – 49,683 barrels per day ($27.34 per barrel) and crude oil and condensate – 11,502 barrels per day ($82.03 per barrel). |
| • | The first quarter average natural gas realized price before hedging settlements was $5.58. Financial hedges based upon NYMEX decreased realizations by $0.48 per mcf and financial basis hedges decreased realizations by $0.90 per mcf during the quarter. The average Company natural gas differential including the settled financial basis hedges but before NYMEX hedging, for the first quarter was $(0.24) per mcf compared to $(0.23) per mcf for the fourth quarter 2013. (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 31% of WTI or $30.30 per barrel for the first quarter of 2014 as ethane was approximately half of the total composite barrel in the Marcellus during the quarter. First quarter 2014 included full ethane deliveries under our Mariner West and ATEX contracts after their start up operations in late 2013. |
| • | Crude oil and condensate price realizations, before financial hedges, for the first quarter averaged 86% of WTI or $85.13 per barrel. |
Effect of Financial Hedges on Non-GAAP natural gas realized prices
Range continues to hedge a significant portion of its production in order to lock in prices and returns which provide certainty of cash flow to execute our capital plans. During the first quarter, unusually cold winter weather created significant natural gas demand and pushed natural gas storage to the lowest level in years. Shortages of natural gas and propane resulted, especially in the northeast, causing temporary price spikes on certain pricing indices. Range realized the actual net price set in by our basis and NYMEX hedges for the quarter while our non-hedged production was able to benefit from the unexpected higher seasonal prices. Our basis and NYMEX hedges provided stable prices during the first quarter. Higher realizations on the physical sale
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of the underlying production resulted in a combined differential of $0.24 below NYMEX, similar to levels realized the past two quarters. As shown in the table, Range’s average differential realized for its Marcellus production for the first quarter was a positive $0.88 per mcf reflecting the strong market pricing obtained by the marketing group. 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.
| 1Q 2013 | 2Q 2013 | 3Q 2013 | 4Q 2013 | 1Q 2014 | ||||||||||||||||
| Corporate Differential Disclosure |
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| NYMEX Index average price |
$ | 3.35 | $ | 4.09 | $ | 3.60 | $ | 3.62 | $ | 4.92 | ||||||||||
| Differential |
$ | 0.15 | $ | 0.04 | ($ | 0.17 | ) | ($ | 0.22 | ) | $ | 0.66 | ||||||||
| Cash settled basis hedging |
$ | 0.00 | $ | 0.00 | $ | 0.00 | ($ | 0.01 | ) | ($ | 0.90 | ) | ||||||||
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| Differential including basis hedging |
$ | 0.15 | $ | 0.04 | ($ | 0.17 | ) | ($ | 0.23 | ) | ($ | 0.24 | ) | |||||||
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| Average price before NYMEX hedges |
$ | 3.50 | $ | 4.13 | $ | 3.43 | $ | 3.39 | $ | 4.68 | ||||||||||
| Cash settled NYMEX hedges |
$ | 0.59 | $ | 0.07 | $ | 0.45 | $ | 0.45 | ($ | 0.48 | ) | |||||||||
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| Average price including all hedges |
$ | 4.09 | $ | 4.20 | $ | 3.88 | $ | 3.84 | $ | 4.20 | ||||||||||
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| Marcellus Only Basis Summary |
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| Total Marcellus |
$ | 0.28 | $ | 0.20 | ($ | 0.06 | ) | ($ | 0.11 | ) | $ | 0.88 | ||||||||
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As of March 31, 2014, Range has basis hedge contracts covering approximately 370,000 Mmbtu per day through October 2014 and another 90,000 Mmbtu per day from November 2014 through March 2015. These basis hedges correspond to actual sales arrangements which are priced based upon the same index as the basis hedge thus locking in the basis differential. The fair value of the basis hedges based upon future strip prices as of March 31, 2014 was a loss of $3.6 million. Range believes that any basis loss actually realized will be offset by the physical sales of natural gas at higher prices which will result in consistent stable basis differentials. We expect the basis hedges to continue to provide stable price protection going forward.
Capital Expenditures
First quarter drilling expenditures of $232 million funded the drilling of 44 (39 net) wells and the completion of previously drilled wells. A 100% drilling success rate was achieved. In addition, during the first quarter, $49 million was expended on acreage, $4 million on gas gathering systems and $14 million for exploration expense. The Company is on track with its 2014 capital expenditure budget of $1.52 billion.
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Guidance – Second Quarter 2014
Production Guidance:
Production growth for 2014 is targeted at 20% to 25% year-over-year. Average daily production for the second quarter of 2014 is expected to range between 1,065 to 1,075 Mmcfe per day, with 30% to 35% liquids. Second quarter production guidance includes the estimated reduction of approximately 50 Mmcfe per day impact for the turnarounds at the MarkWest processing plants which shut down all of our wet gas production for all or part of seven days. Third quarter production guidance is expected to average between 1,160 to 1,210 Mmcfe per day, with 30% to 35% liquids and fourth quarter production guidance is expected to average between 1,280 to 1,340 Mmcfe per day, with 30% to 35% liquids as more wells are turned to sales and the 2014 program wells begin production.
Guidance for 2014 Activity:
Under the current plan, which will be subject to change during the year, Range expects to turn to sales approximately 163 wells in the Marcellus and Midcontinent during 2014, as shown below:
| Wells in First Quarter 2014 |
Remaining 2014 Wells |
Planned Total Wells to Sales in 2014 |
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| Super-Rich area |
4 | 53 | 57 | |||||||||
| Wet area |
8 | 47 | 55 | |||||||||
| Dry area-SW |
1 | 12 | 13 | |||||||||
| Dry area-NE |
1 | 13 | 14 | |||||||||
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| Total Marcellus |
14 | 125 | 139 | |||||||||
| Midcontinent |
6 | 16 | 22 | |||||||||
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| Total |
20 | 141 | 161 | |||||||||
Expense per mcfe Guidance:
| Direct operating expense: $0.36 - $0.38 per mcfe |
| Transportation, gathering and compression expense: $0.86 - $0.88 per mcfe |
| Production tax expense: $0.14 - $0.16 per mcfe |
| Exploration expense: $16 - $18 million |
| Unproved property impairment expense: $10 - $12 million |
| G&A expense: $0.38 - $0.40 per mcfe |
| Interest expense: $0.47 - $0.49 per mcfe |
| DD&A expense: $1.36 - $1.39 per mcfe |
NYMEX Hedging Status
Range hedges portions of its expected future production volumes to increase the predictability of cash flow and to help maintain a strong, flexible financial position. Range currently has over 80% of its remaining 2014 natural gas production hedged at a weighted average floor price of $3.96 per Mmbtu and a weighted average ceiling price of $4.38 per Mmbtu. Similarly, Range has hedged more than 90% of its remaining 2014 projected crude oil production at a floor price of $92.82 per barrel and approximately 50% of its composite NGL production.
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For calendar year 2015, Range has hedged just over 422,000 Mmbtu per day of its expected natural gas production at a weighted average floor price of $4.17 per Mmbtu and a weighted average ceiling price of $4.33 per Mmbtu. Similarly, Range has hedged almost 6,500 barrels per day of its 2015 projected crude oil production at a floor price of $89.70 per barrel with none of its expected NGL production hedged due to the backwardation of the future price curve. Please see Range’s detailed hedging schedule posted at the end of the financial tables below and on its website at www.rangeresources.com.
Effective March 1, 2013, Range elected to discontinue hedge accounting for derivative contracts and moved to mark-to-market accounting for its derivative contracts. The mark-to-market accounting treatment may create fluctuations in earnings as commodity prices change both positively and negatively, however, such mark-to-market adjustments have no cash flow impact. The impact to cash flow will occur as the underlying contracts are settled. As of March 31, 2014, the Company expects to reclassify into earnings in 2014, $5.0 million of unrealized net gains frozen in accumulated other comprehensive income due to the discontinuance of hedge accounting.
Conference Call Information
A conference call to review the financial results is scheduled on Tuesday, April 29 at 9:00 a.m. ET. To participate in the call, please dial 877-407-0778 and ask for the Range Resources first quarter 2014 financial results conference call. A replay of the call will be available through May 29. To access the phone replay dial 877-660-6853. The conference ID is 13579010.
A simultaneous webcast of the call may be accessed over the Internet at http://www.rangeresources.com. The webcast will be archived for replay on the Company’s website until May 29.
Non-GAAP Financial Measures:
Adjusted net income comparable to analysts’ estimates as set forth in this release represents income or loss from operations before income taxes adjusted for certain non-cash items (detailed below and in the accompanying table) less income taxes. We believe adjusted net income comparable to analysts’ estimates is calculated on the same basis as analysts’ estimates and that many investors use this published research in making investment decisions useful in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Diluted earnings per share (adjusted) as set forth in this release represents adjusted net income comparable to analysts’ estimates on a diluted per share basis. A table is included which reconciles income or loss from operations to adjusted net income comparable to analysts’ estimates and diluted earnings per share (adjusted). On its website, the Company provides additional comparative information on prior periods along with non-GAAP revenue disclosures.
Cash flow from operations before changes in working capital (sometimes referred to as “adjusted cash flow”) as defined in this release represents net cash provided by operations before changes in working capital and exploration expense adjusted for certain non-cash compensation items. Cash flow from operations before changes in working capital is widely accepted by the investment community as a financial indicator of an oil and gas company’s ability to generate cash to internally fund exploration and development activities and to service debt. Cash flow from operations before changes in working capital is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Cash flow from operations before changes in working capital is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operations, investing, or financing activities as an indicator of cash flows, or as a measure of liquidity. A table is included which reconciles Net cash provided by operations to Cash flow from operations before changes in working capital as used in this release. On its website, the Company provides additional comparative information on prior periods for cash flow, cash margins and non-GAAP earnings as used in this release.
The cash prices realized for oil and natural gas production including the amounts realized on cash-settled derivatives and net of transportation, gathering and compression expense is a critical component in the Company’s performance tracked by investors and professional research analysts in valuing, comparing, rating and providing investment recommendations and forecasts of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Due to the GAAP disclosures of various derivative transactions and third party transportation, gathering and compression expense, such information is now reported in various lines of the income statement. The Company believes that it is important to furnish a table reflecting the details of the various components of each income statement line to better inform the reader of the details of each amount and provide a summary of the realized cash-settled amounts and third party transportation, gathering and compression expense which historically were reported as natural gas, NGLs and oil sales. This information will serve to bridge the gap between various readers’ understanding and fully disclose the information needed.
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The Company discloses in this release the detailed components of many of the single line items shown in the unaudited GAAP financial statements included in the Company’s Quarterly Report on Form 10-Q. The Company believes that it is important to furnish this detail of the various components comprising each line of the Statements of Operations to better inform the reader of the details of each amount, the changes between periods and the effect on its financial results.
Hedging and Derivatives
As discussed in this news release, Range has reclassified within total revenues its financial reporting of the cash settlement of its commodity derivatives. Under this presentation, those hedges considered “effective” under ASC 815 are included in “Natural gas, NGLs and oil sales” when settled. For undesignated hedges and those hedges designated to regions where the historical correlation between NYMEX and regional prices is “non-highly effective” or is “volumetric ineffective” due to sale of the underlying reserves, they are deemed to be “derivatives” and the cash settlements are included in a separate line item shown as “Derivative fair value income (loss)” in the consolidated statements of operations included in the Company’s Form 10-Q along with the change in mark-to-market valuations of such unrealized derivatives. Effective March 1, 2013, the Company de-designated all commodity contracts and elected to discontinue hedge accounting prospectively. The Company has provided additional information regarding natural gas, NGLs and oil sales in a supplemental table included with this release, which would correspond to amounts shown by analysts for natural gas, NGLs and oil sales realized, including cash-settled derivatives.
RANGE RESOURCES CORPORATION (NYSE: 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. More information about Range can be found at http://www.rangeresources.com/.
All statements, except for statements of historical fact, made in this release such as expected future growth in production, low-reinvestment risk, future commodity prices, improved well performance, expected greater capital efficiency, future rates of return, continued drilling improvements, future capital spending plans, cost structure improvements, planned exports, expected future basis realizations, expected drilling and development plans and future guidance information are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These statements are based on assumptions and estimates that management believes are reasonable based on currently available information; however, management’s assumptions and Range’s future performance are subject to a wide range of business risks and uncertainties and there is no assurance that these goals and projections can or will be met. Any number of factors could cause actual results to differ materially from those in the forward-looking statements, including, but not limited to, the volatility of oil and gas prices, the results of our hedging transactions, the costs and results of drilling and operations, the timing of production, mechanical and other inherent risks associated with oil and gas production, weather, the availability of drilling equipment, changes in interest rates, litigation, uncertainties about reserve estimates, environmental risks and regulatory changes. Range undertakes no obligation to publicly update or revise any forward-looking statements. Further information on risks and uncertainties is available in Range’s filings with the Securities and Exchange Commission (“SEC”), which are incorporated by reference.
The SEC permits oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions as well as the option to disclose probable and possible reserves. Range has elected not to disclose the Company’s probable and possible reserves in its filings with the SEC. Range uses certain broader terms such as “resource potential,” or “unproved resource potential” or “upside” or other descriptions of volumes of resources potentially recoverable through additional drilling or recovery techniques that may include probable and possible reserves as defined by the SEC’s guidelines. Range has not attempted to distinguish probable and possible reserves from these broader classifications. The SEC’s rules prohibit us from including in filings with the SEC these broader classifications of reserves. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of actually being realized. Unproved resource potential refers to Range’s internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques and have not been reviewed by independent engineers. Unproved resource potential does not constitute reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System and does not
8
include proved reserves. Area wide unproven resource potential has not been fully risked by Range’s management. “EUR,” or estimated ultimate recovery, refers to our management’s estimates of hydrocarbon quantities that may be recovered from a well completed as a producer in the area. These quantities may not necessarily constitute or represent reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or the SEC’s oil and natural gas disclosure rules. Actual quantities that may be recovered from Range’s interests could differ substantially. Factors affecting ultimate recovery include the scope of Range’s drilling program, which will be directly affected by the availability of capital, drilling and production costs, commodity prices, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals, field spacing rules, recoveries of gas in place, length of horizontal laterals, actual drilling results, including geological and mechanical factors affecting recovery rates and other factors. Estimates of resource potential may change significantly as development of our resource plays provides additional data. Investors are urged to consider closely the disclosure in our most recent Annual Report on Form 10-K, available from our website at www.rangeresources.com or by written request to 100 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102. You can also obtain this Form 10-K by calling the SEC at 1-800-SEC-0330.
2014-07
SOURCE: Range Resources Corporation
Investor Contacts:
Rodney Waller, Senior Vice President
817-869-4258
rwaller@rangeresources.com
David Amend, Investor Relations Manager
817-869-4266
damend@rangeresources.com
Laith Sando, Research Manager
817-869-4267
lsando@rangeresources.com
Michael Freeman, Financial Analyst
817-869-4264
mfreeman@rangeresources.com
or
Media Contact:
Matt Pitzarella, Director of Corporate Communications
724-873-3224
mpitzarella@rangeresources.com
www.rangeresources.com
9
RANGE RESOURCES CORPORATION
STATEMENTS OF OPERATIONS
Based on GAAP reported earnings with additional
details of items included in each line in Form 10-Q
(Unaudited, in thousands, except per share data)
| Three Months Ended March 31, | ||||||||||||
| 2014 | 2013 | % | ||||||||||
| Revenues and other income: |
||||||||||||
| Natural gas, NGLs and oil sales (a) |
$ | 572,017 | $ | 398,239 | ||||||||
| Derivative fair value (loss) income |
(146,850 | ) | (99,875 | ) | ||||||||
| Gain (loss) on sale of assets |
(353 | ) | (166 | ) | ||||||||
| Brokered natural gas, marketing and other (c) |
33,249 | 21,058 | ||||||||||
| Equity method investment (c) |
(133 | ) | (80 | ) | ||||||||
| ARO settlement loss (c) |
(659 | ) | — | |||||||||
| Other (c) |
71 | 63 | ||||||||||
|
|
|
|
|
|||||||||
| Total revenues and other income |
457,342 | 319,239 | 43 | % | ||||||||
|
|
|
|
|
|||||||||
| Costs and expenses: |
||||||||||||
| Direct operating |
38,943 | 29,527 | ||||||||||
| Direct operating – non-cash stock-based compensation (b) |
852 | 661 | ||||||||||
| Transportation, gathering and compression |
74,161 | 62,416 | ||||||||||
| Production and ad valorem taxes |
11,678 | 11,383 | ||||||||||
| Brokered natural gas and marketing |
33,601 | 22,066 | ||||||||||
| Brokered natural gas and marketing – non-cash stock-based compensation (b) |
528 | 249 | ||||||||||
| Exploration |
13,693 | 15,710 | ||||||||||
| Exploration – non-cash stock-based compensation (b) |
1,153 | 1,070 | ||||||||||
| Abandonment and impairment of unproved properties |
9,995 | 15,218 | ||||||||||
| General and administrative |
37,200 | 35,354 | ||||||||||
| General and administrative – non-cash stock-based compensation (b) |
11,604 | 10,306 | ||||||||||
| General and administrative – lawsuit settlements |
408 | 38,398 | ||||||||||
| Deferred compensation plan (d) |
(2,035 | ) | 42,360 | |||||||||
| Interest expense |
45,401 | 42,210 | ||||||||||
| Depletion, depreciation and amortization |
128,682 | 115,101 | ||||||||||
|
|
|
|
|
|||||||||
| Total costs and expenses |
405,864 | 442,029 | -8 | % | ||||||||
|
|
|
|
|
|||||||||
| Income (loss) from operations before income taxes |
51,478 | (122,790 | ) | 142 | % | |||||||
| Income tax expense (benefit): |
||||||||||||
| Current |
6 | 25 | ||||||||||
| Deferred |
18,951 | (47,205 | ) | |||||||||
|
|
|
|
|
|||||||||
| 18,957 | (47,180 | ) | ||||||||||
|
|
|
|
|
|||||||||
| Net income (loss) |
$ | 32,521 | $ | (75,610 | ) | 143 | % | |||||
|
|
|
|
|
|||||||||
| Net Income (Loss) Per Common Share: |
||||||||||||
| Basic |
$ | 0.20 | $ | (0.47 | ) | |||||||
|
|
|
|
|
|||||||||
| Diluted |
$ | 0.20 | $ | (0.47 | ) | |||||||
|
|
|
|
|
|||||||||
| Weighted average common shares outstanding, as reported: |
||||||||||||
| Basic |
160,794 | 160,125 | 0 | % | ||||||||
| Diluted |
161,825 | 160,125 | 1 | % | ||||||||
| (a) | See separate natural gas, NGLs and oil sales information table. |
| (b) | Costs associated with stock compensation and restricted stock amortization, which have been reflected in the categories associated with the direct personnel costs, which are combined with the cash costs in the 10-Q. |
| (c) | Included in Brokered natural gas, marketing and other revenues in the 10-Q. |
| (d) | Reflects the change in market value of the vested Company stock held in the deferred compensation plan. |
10
RANGE RESOURCES CORPORATION
BALANCE SHEETS
| March 31, | December 31, | |||||||
| 2014 | 2013 | |||||||
| (In thousands) | (Unaudited) | (Audited) | ||||||
| Assets |
||||||||
| Current assets |
$ | 238,903 | $ | 192,466 | ||||
| Derivative assets |
80 | 4,421 | ||||||
| Deferred tax assets |
40,362 | 51,414 | ||||||
| Natural gas and oil properties, successful efforts method |
6,912,654 | 6,758,437 | ||||||
| Transportation and field assets |
32,081 | 32,784 | ||||||
| Other |
258,695 | 259,564 | ||||||
|
|
|
|
|
|||||
| $ | 7,482,775 | $ | 7,299,086 | |||||
|
|
|
|
|
|||||
| Liabilities and Stockholders’ Equity |
||||||||
| Current liabilities |
$ | 470,644 | $ | 464,326 | ||||
| Asset retirement obligations |
5,037 | 5,037 | ||||||
| Derivative liabilities |
72,854 | 26,198 | ||||||
| Bank debt |
594,000 | 500,000 | ||||||
| Subordinated notes |
2,640,866 | 2,640,516 | ||||||
|
|
|
|
|
|||||
| 3,234,866 | 3,140,516 | |||||||
|
|
|
|
|
|||||
| Deferred tax liability |
778,955 | 771,980 | ||||||
| Derivative liabilities |
142 | 25 | ||||||
| Deferred compensation liability |
235,307 | 247,537 | ||||||
| Asset retirement obligations and other liabilities |
235,289 | 229,015 | ||||||
|
|
|
|
|
|||||
| 1,249,693 | 1,248,557 | |||||||
| Common stock and retained earnings |
2,448,140 | 2,411,853 | ||||||
| Common stock held in treasury stock |
(3,455 | ) | (3,637 | ) | ||||
|
|
|
|
|
|||||
| 2,444,685 | 2,408,216 | |||||||
| Accumulated other comprehensive income |
4,996 | 6,236 | ||||||
|
|
|
|
|
|||||
| Total stockholders’ equity |
2,449,681 | 2,414,452 | ||||||
|
|
|
|
|
|||||
| $ | 7,482,775 | $ | 7,299,086 | |||||
|
|
|
|
|
|||||
RECONCILIATION OF TOTAL REVENUES AND
OTHER INCOME TO TOTAL REVENUE EXCLUDING
CERTAIN ITEMS, a non-GAAP measure
| Three Months Ended March 31, | ||||||||||||
| (Unaudited, in thousands) | 2014 | 2013 | % | |||||||||
| Total revenues and other income, as reported |
$ | 457,342 | $ | 319,239 | 43 | % | ||||||
| Adjustment for certain special items: |
||||||||||||
| Total change in fair value related to derivatives prior to settlement (gain) loss |
42,266 | 100,257 | ||||||||||
| ARO settlement loss |
659 | — | ||||||||||
| (Gain) loss on sale of assets |
353 | 166 | ||||||||||
|
|
|
|
|
|||||||||
| Total revenues, as adjusted, non-GAAP |
$ | 500,620 | $ | 419,662 | 19 | % | ||||||
|
|
|
|
|
|||||||||
11
RANGE RESOURCES CORPORATION
CASH FLOWS FROM OPERATING ACTIVITIES
| Three Months Ended March 31, | ||||||||
| (Unaudited, in thousands) | 2014 | 2013 | ||||||
| Net income (loss) |
$ | 32,521 | $ | (75,610 | ) | |||
| Adjustments to reconcile net cash provided from continuing operations: |
||||||||
| (Gain) Loss from equity method investment, net of distributions |
2,732 | 610 | ||||||
| Deferred income tax expense (benefit) |
18,951 | (47,205 | ) | |||||
| Depletion, depreciation, amortization and impairment |
128,682 | 115,101 | ||||||
| Exploration dry hole costs |
1 | (159 | ) | |||||
| Abandonment and impairment of unproved properties |
9,995 | 15,218 | ||||||
| Derivative fair value loss (income) |
146,850 | 99,875 | ||||||
| Cash settlements on derivative financial instruments that do not qualify for hedge accounting |
(104,584 | ) | 382 | |||||
| Amortization of deferred issuance costs, loss on extinguishment of debt and other |
2,873 | 2,080 | ||||||
| Deferred and stock-based compensation |
12,593 | 54,991 | ||||||
| Gain (loss) on sale of assets and other |
353 | 166 | ||||||
| Changes in working capital: |
||||||||
| Accounts receivable |
(41,643 | ) | 1,292 | |||||
| Inventory and other |
(5,358 | ) | 166 | |||||
| Accounts payable |
9,997 | 17,061 | ||||||
| Accrued liabilities and other |
(32,742 | ) | 17,281 | |||||
|
|
|
|
|
|||||
| Net changes in working capital |
(69,746 | ) | 35,800 | |||||
|
|
|
|
|
|||||
| Net cash provided from operating activities |
$ | 181,221 | $ | 201,249 | ||||
|
|
|
|
|
|||||
RECONCILIATION OF NET CASH PROVIDED FROM OPERATING
ACTIVITIES, AS REPORTED, TO CASH FLOW FROM OPERATIONS BEFORE CHANGES
IN WORKING CAPITAL, a non-GAAP measure
| Three Months Ended March 31, | ||||||||
| (Unaudited, in thousands) | 2014 | 2013 | ||||||
| Net cash provided from operating activities, as reported |
$ | 181,221 | $ | 201,249 | ||||
| Net changes in working capital |
69,746 | (35,800 | ) | |||||
| Exploration expense |
13,692 | 15,869 | ||||||
| Lawsuit settlements |
408 | 38,398 | ||||||
| Equity method investment distribution / intercompany elimination |
(2,599 | ) | (531 | ) | ||||
| Non-cash compensation adjustment |
(366 | ) | (206 | ) | ||||
|
|
|
|
|
|||||
| Cash flow from operations before changes in working capital—a non-GAAP measure |
$ | 262,102 | $ | 218,979 | ||||
|
|
|
|
|
|||||
| ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING |
||||||||
| Three Months Ended March 31, | ||||||||
| (Unaudited, in thousands) | 2014 | 2013 | ||||||
| Basic: |
||||||||
| Weighted average shares outstanding |
163,609 | 162,840 | ||||||
| Stock held by deferred compensation plan |
(2,815 | ) | (2,715 | ) | ||||
|
|
|
|
|
|||||
| Adjusted basic |
160,794 | 160,125 | ||||||
|
|
|
|
|
|||||
| Dilutive: |
||||||||
| Weighted average shares outstanding |
163,609 | 162,840 | ||||||
| Dilutive stock options under treasury method |
(1,784 | ) | (2,715 | ) | ||||
|
|
|
|
|
|||||
| Adjusted dilutive |
161,825 | 160,125 | ||||||
|
|
|
|
|
|||||
12
RANGE RESOURCES CORPORATION
RECONCILIATION OF NATURAL GAS, NGLs AND OIL
SALES AND DERIVATIVE FAIR VALUE INCOME (LOSS) TO CALCULATED CASH REALIZED NATURAL GAS,
NGLs AND OIL PRICES WITH AND WITHOUT THIRD PARTY
TRANSPORTATION, GATHERING AND COMPRESSION FEES non-GAAP measures
| Three Months Ended March 31, | ||||||||||||
| (Unaudited, in thousands, except per unit data) |
2014 | 2013 | % | |||||||||
| Natural gas, NGL and Oil Sales components: |
||||||||||||
| Natural Gas Sales |
$ | 346,226 | $ | 217,088 | ||||||||
| NGL Sales |
135,504 | 67,571 | ||||||||||
| Oil Sales |
88,121 | 77,080 | ||||||||||
| Cash-settled hedges (effective): |
||||||||||||
| Natural Gas |
1,168 | 35,478 | ||||||||||
| Crude Oil |
998 | 1,022 | ||||||||||
|
|
|
|
|
|||||||||
| Total Oil and Gas Sales, as reported |
$ | 572,017 | $ | 398,239 | 44 | % | ||||||
|
|
|
|
|
|||||||||
| Derivative Fair Value Income (Loss), as reported |
$ | (146,850 | ) | $ | (99,875 | ) | ||||||
| Cash settlements on derivative financial instruments – (gain) loss: |
||||||||||||
| Natural Gas |
87,108 | (1,379 | ) | |||||||||
| NGLs |
13,272 | 895 | ||||||||||
| Crude Oil |
4,204 | 102 | ||||||||||
|
|
|
|
|
|||||||||
| Total change in fair value related to derivatives prior to settlement, a non-GAAP measure |
$ | (42,266 | ) | $ | (100,257 | ) | ||||||
|
|
|
|
|
|||||||||
| Transportation, Gathering and Compression components: |
||||||||||||
| Natural Gas |
$ | 65,299 | $ | 59,241 | ||||||||
| NGLs |
8,862 | 3,175 | ||||||||||
|
|
|
|
|
|||||||||
| Total transportation, gathering and compression, as reported |
$ | 74,161 | $ | 62,416 | ||||||||
|
|
|
|
|
|||||||||
| Natural gas, NGL and Oil sales, including cash-settled derivatives (c): |
||||||||||||
| Natural Gas Sales |
$ | 260,286 | $ | 253,945 | ||||||||
| NGL Sales |
122,232 | 66,676 | ||||||||||
| Oil Sales |
84,915 | 78,000 | ||||||||||
|
|
|
|
|
|||||||||
| Total |
$ | 467,433 | $ | 398,621 | 17 | % | ||||||
|
|
|
|
|
|||||||||
| Production of Oil and Gas during the periods (a): |
||||||||||||
| Natural Gas (mcf) |
62,017,581 | 62,023,956 | 0 | % | ||||||||
| NGL (bbl) |
4,471,481 | 1,889,424 | 137 | % | ||||||||
| Oil (bbl) |
1,035,145 | 912,662 | 13 | % | ||||||||
| Gas equivalent (mcfe) (b) |
95,057,337 | 78,836,472 | 21 | % | ||||||||
| Production of Oil and Gas – average per day (a): |
||||||||||||
| Natural Gas (mcf) |
689,084 | 689,155 | 0 | % | ||||||||
| NGL (bbl) |
49,683 | 20,994 | 137 | % | ||||||||
| Oil (bbl) |
11,502 | 10,141 | 13 | % | ||||||||
| Gas equivalent (mcfe) (b) |
1,056,193 | 875,961 | 21 | % | ||||||||
| Average prices, including cash settled hedges that qualify for hedge accounting before third party transportation costs: |
||||||||||||
| Natural Gas (per mcf) |
$ | 5.60 | $ | 4.07 | 38 | % | ||||||
| NGL (per bbl) |
$ | 30.30 | $ | 35.76 | -15 | % | ||||||
| Oil (per bbl) |
$ | 86.09 | $ | 85.58 | 1 | % | ||||||
| Gas equivalent (per mcfe) (b) |
$ | 6.02 | $ | 5.05 | 19 | % | ||||||
| Average prices, including cash-settled hedges and derivatives before third party transportation costs (c): |
||||||||||||
| Natural Gas (per mcf) |
$ | 4.20 | $ | 4.09 | 3 | % | ||||||
| NGL (per bbl) |
$ | 27.34 | $ | 35.29 | -23 | % | ||||||
| Oil (per bbl) |
$ | 82.03 | $ | 85.46 | -4 | % | ||||||
| Gas equivalent (per mcfe) (b) |
$ | 4.92 | $ | 5.06 | -3 | % | ||||||
| Average prices, including cash-settled hedges and derivatives (d): |
||||||||||||
| Natural Gas (per mcf) |
$ | 3.14 | $ | 3.14 | 0 | % | ||||||
| NGL (per bbl) |
$ | 25.35 | $ | 33.61 | -25 | % | ||||||
| Oil (per bbl) |
$ | 82.03 | $ | 85.46 | -4 | % | ||||||
| Gas equivalent (per mcfe) (b) |
$ | 4.14 | $ | 4.26 | -3 | % | ||||||
| Transportation, gathering and compression expense per mcfe |
$ | 0.78 | $ | 0.79 | -1 | % | ||||||
| (a) | Represents volumes sold regardless of when produced. |
| (b) | Oil and NGLs are converted at the rate of one barrel equals six mcfe based upon the approximate relative energy content of oil to natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices. |
| (c) | Excluding third party transportation, gathering and compression costs. |
| (d) | Net of transportation, gathering and compression costs. |
13
RANGE RESOURCES CORPORATION
RECONCILIATION OF INCOME (LOSS) FROM CONTINUING
OPERATIONS BEFORE INCOME TAXES AS REPORTED TO
INCOME FROM OPERATIONS BEFORE INCOME TAXES
EXCLUDING CERTAIN ITEMS, a non-GAAP measure
| (Unaudited, in thousands, except per share data) | Three Months Ended March 31, | |||||||||||
| 2014 | 2013 | % | ||||||||||
| Income (loss) from operations before income taxes, as reported |
$ | 51,478 | $ | (122,790 | ) | 142 | % | |||||
| Adjustment for certain special items: |
||||||||||||
| Loss (gain) on sale of assets |
353 | 166 | ||||||||||
| Loss on ARO settlements |
659 | — | ||||||||||
| Change in fair value related to derivatives prior to settlement |
42,266 | 100,257 | ||||||||||
| Abandonment and impairment of unproved properties |
9,995 | 15,218 | ||||||||||
| Lawsuit settlements |
408 | 38,398 | ||||||||||
| Brokered natural gas and marketing – non-cash stock-based compensation |
528 | 249 | ||||||||||
| Direct operating – non-cash stock-based compensation |
852 | 661 | ||||||||||
| Exploration expenses – non-cash stock-based compensation |
1,153 | 1,070 | ||||||||||
| General & administrative – non-cash stock-based compensation |
11,604 | 10,306 | ||||||||||
| Deferred compensation plan – non-cash adjustment |
(2,035 | ) | 42,360 | |||||||||
|
|
|
|
|
|||||||||
| Income from operations before income taxes, as adjusted |
117,261 | 85,895 | 37 | % | ||||||||
| Income tax expense, as adjusted: |
||||||||||||
| Current |
6 | 25 | ||||||||||
| Deferred |
43,179 | 32,993 | ||||||||||
|
|
|
|
|
|||||||||
| Net income excluding certain items, a non-GAAP measure |
$ | 74,076 | $ | 52,877 | 40 | % | ||||||
|
|
|
|
|
|||||||||
| Non-GAAP income per common share |
||||||||||||
| Basic |
$ | 0.46 | $ | 0.33 | 39 | % | ||||||
|
|
|
|
|
|||||||||
| Diluted |
$ | 0.46 | $ | 0.33 | 39 | % | ||||||
|
|
|
|
|
|||||||||
| Non-GAAP diluted shares outstanding, if dilutive |
161,825 | 160,996 | ||||||||||
|
|
|
|
|
|||||||||
14
RANGE RESOURCES CORPORATION
HEDGING POSITION AS OF APRIL 22, 2014 –
(Unaudited)
| Daily Volume | Hedge Price | |||||
| Gas (Mmbtu) |
||||||
| 2Q 2014 Swaps |
200,000 | $4.17 | ||||
| 2Q 2014 Collars |
447,500 | $3.84 - $4.48 | ||||
| 3Q 2014 Swaps |
260,000 | $4.18 | ||||
| 3Q 2014 Collars |
447,500 | $3.84 - $4.48 | ||||
| 4Q 2014 Swaps |
260,000 | $4.18 | ||||
| 4Q 2014 Collars |
447,500 | $3.84 - $4.48 | ||||
| 2015 Swaps |
277,432 | $4.21 | ||||
| 2015 Collars |
145,000 | $4.07 - $4.56 | ||||
| 2016 Swaps |
72,500 | $4.19 | ||||
| Oil (Bbls) |
||||||
| 2Q 2014 Swaps |
8,500 | $94.51 | ||||
| 2Q 2014 Collars |
2,000 | $85.55 - $100.00 | ||||
| 3Q 2014 Swaps |
9,500 | $94.35 | ||||
| 3Q 2014 Collars |
2,000 | $85.55 - $100.00 | ||||
| 4Q 2014 Swaps |
9,500 | $94.35 | ||||
| 4Q 2014 Collars |
2,000 | $85.55 - $100.00 | ||||
| 2015 Swaps |
6,496 | $89.70 | ||||
| C3 Propane (Bbls) |
||||||
| 2Q 2014 Swaps |
12,000 | $1.016 | ||||
| 3Q 2014 Swaps |
12,000 | $1.018 | ||||
| 4Q 2014 Swaps |
12,000 | $1.018 | ||||
| C4 Normal Butane (Bbls) | ||||||
| 2Q 2014 Swaps |
4,000 | $1.344 | ||||
| 3Q 2014 Swaps |
4,000 | $1.344 | ||||
| 4Q 2014 Swaps |
4,000 | $1.344 | ||||
| C5 Natural Gasoline (Bbls) | ||||||
| 2Q 2014 Swaps |
1,000 | $2.113 | ||||
NOTE: SEE WEBSITE FOR OTHER SUPPLEMENTAL INFORMATION FOR THE PERIODS
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