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): July 25, 2013 (July 24, 2013)
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 July 24, 2013 Range Resources Corporation issued a press release announcing its second quarter 2013 results. A copy of this press release is being furnished as an exhibit to this report on Form 8-K.
The information in this Form 8-K, including the accompanying Exhibit 99.1, shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 (the “Exchange Act”), or otherwise subject to the liability of such section, nor shall such information be deemed incorporated by reference in any filing under the Securities Act of 1933 of the Exchange Act, regardless of the general incorporation language of such filing, except as shall be expressly set forth by specific reference in such filing.
| ITEM 9.01 | Financial Statements and Exhibits |
(d) Exhibits:
| 99.1 | Press Release dated July 24, 2013 |
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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: July 25, 2013
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EXHIBIT INDEX
| Exhibit Number |
Description | |
| 99.1 | Press Release dated July 24, 2013 | |
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EXHIBIT 99.1
RANGE ANNOUNCES SECOND QUARTER 2013 RESULTS
FORT WORTH, TEXAS, July 24, 2013…RANGE RESOURCES CORPORATION (NYSE: RRC) today announced its second quarter 2013 financial results.
Second Quarter Highlights –
| • | Record daily production of 910 Mmcfe per day, an increase of 27% over the prior-year quarter; 30% adjusted for the New Mexico asset sale |
| • | Adjusted cash flow was $227 million, an increase of 46% as compared to the prior year quarter |
| • | Unit costs decline 7% as compared to the prior-year quarter |
| • | New Mexico asset sale for $275 million closed April 1st generating $83 million pre-tax gain |
| • | Class leading liquids-rich wells drilled in Pennsylvania continue to provide impressive results |
| • | Initial ethane deliveries to Mariner West commenced July 21st |
Changes in Guidance –
| • | Type curve and EUR increased 38% over the 2012 type curve in the super-rich SW PA area to 1.82 Mmboe (10.9 Bcfe) |
| • | Type curve and EUR increased 41% in wet SW PA area to 12.3 Bcfe |
| • | Type curve and EUR increased 63% in dry SW PA area to 12.2 Bcf |
| • | Tighter spacing positive test results with 500 feet between laterals in Marcellus adds 12 to 15 Tcfe of unproved resource potential attributable to the super-rich and wet areas in the southwest |
Commenting on the announcement, Jeff Ventura, Range’s President and CEO, said, “Range had an impressive first half of 2013, continuing to set record production results while decreasing our unit costs. Our balance sheet and liquidity are set for continued growth as outlined in our business plan of growing production 20% to 25% for many years. Importantly, cash flow growth is expected to outpace our production growth percentage. With the progress made during the first half of 2013, we are focused on the higher end of our production growth range for 2013. The first deliveries of ethane into Mariner West to Sarnia, Canada commenced start up operations on July 21st. Range has access to the only operating de-ethanizer in Appalachia while others are still under construction. This will allow us to continue our planned growth without concern for pipeline quality requirements. Additional ethane and propane transportation projects are scheduled to become operational next year conforming to our growth plans. Our growth is led by our approximate one million acre leasehold position in Pennsylvania which essentially doubles when stacked pay reservoirs across most of our acreage in the Basin are considered. This acreage position is anchored by the Marcellus, one of the most prolific reservoirs in the U.S. We believe that our 20% to 25% production growth that we expect to deliver for many years, coupled with the high returns, low cost and low reinvestment risk will drive substantial per share value for our shareholders for years to come.”
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.)
GAAP revenues for the second quarter of 2013 totaled $673 million (a 50% increase as compared to second quarter 2012), GAAP net cash provided from operating activities including changes in working capital was $79 million (a 38% decrease as compared to second quarter 2012 primarily due to the payment of a previously announced legal settlement) and GAAP earnings increased by 159% to $144 million ($0.88 per diluted share) versus $56 million ($0.34 per diluted share) in the second quarter 2012.
Non-GAAP revenues for second quarter 2013 totaled $431 million (a 36% increase as compared to second quarter 2012), cash flow from operations before changes in working capital, a non-GAAP measure, reached $227 million ($1.40 per diluted share, and a 46% increase as compared to second quarter 2012). Adjusted net income, a non-GAAP measure, was $55 million ($0.34 per diluted share, and a 204% increase as compared to second quarter 2012).
Several non-cash or non-recurring items impacted second quarter results. A $159.5 million mark-to-market commodity hedge gain was recorded. An $83.3 million gain on sale of properties was recognized primarily on the sale of New Mexico properties, effective April 1, 2013. A $52.9 million charge for lawsuit settlements was recorded, and $15.4 million of non-cash stock compensation expenses were recorded while a reduction in deferred compensation expense of $6.9 million was recognized with the decrease in the common stock price between quarters in the second quarter.
Reviewing the Company’s six major expense categories of direct operating expense, transportation, gathering and compression expense, production and ad valorem tax expense, general and administrative expense, interest expense and depletion, depreciation and amortization expense, total unit costs decreased by $0.30 per mcfe or 7% compared to the prior-year quarter led by decreases in production and ad valorem tax expense (-24%), interest expense (-18%), depreciation, depletion and amortization expense (-13%), general and administrative expense (-9%) and direct operating expense (-3%). These reductions more than offset a $0.12 per mcfe increase in transportation cost related to Range’s increased Marcellus activity and moving natural gas to more favorable markets.
As previously reported, second quarter production volumes reached a record high, averaging 910 Mmcfe per day, a 27% increase over the prior-year quarter. Year-over-year oil and condensate production increased 39%, NGL production rose 35%, while natural gas production increased 24%. Adjusting for the sale of the New Mexico properties which closed on April 1, 2013 comprising production of approximately 18 Mmcfe per day with 30% being liquids, second quarter production would have increased 30% over the prior year quarter with oil and condensate production increasing 57%, NGL production increasing 35% and natural gas production increasing 27%. The record production was driven by the continued success of the Company’s drilling program primarily in the Marcellus Shale. Realized prices, after adjustment for all cash-settled hedges, averaged $5.02 per mcfe, a 6% increase from the prior-year period. Production and realized prices by each commodity for the second quarter were: natural gas – 713 Mmcf per day ($4.20 per mcf), NGLs – 23,247 barrels per day ($32.91 per barrel) and crude oil and condensate – 9,500 barrels per day ($85.09 per barrel).
See “Non-GAAP Financial Measures” for a definition of each of these non-GAAP financial measures and tables that reconcile each of these non-GAAP measures to their most directly comparable GAAP financial measure which are posted here and on our website.
Capital Expenditures
Second quarter drilling expenditures of $262 million funded the drilling of 79 (73 net) wells and the completion of previously drilled wells. A 100% drilling success rate was achieved. In addition, during the second quarter, $22 million was expended on acreage purchases, $14 million on gas gathering systems and $12 million on exploration expense. The Company remains on track with its 2013 capital expenditure budget of $1.3 billion.
Balance Sheet
During the second quarter, Range closed the $275 million sale of its New Mexico properties. The net proceeds were used to reduce the outstanding balance on the Company’s bank credit facility. In addition, in May, Range completed the redemption for all $250 million in outstanding principal of its 7.25% Senior Subordinated Notes due 2018. The principal along with the $9.1 million redemption premium was funded using borrowings under the bank credit facility. As a result, Range currently has no senior subordinated note maturities until 2019. At the end of the second quarter, the Company had approximately $1.4 billion of committed liquidity available under its $1.75 billion bank commitment amount and $2.0 billion bank credit facility borrowing base.
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Operational Discussion
Range has updated its investor presentation with updated pricing in its economic sensitivity analysis, revised EURs and type curves in southwest Pennsylvania and other financial and operational information. Please see www.rangeresources.com under the Investor Relations tab, “Presentations and Webcasts” area, for the presentation entitled, “Company Presentation – July 2013.”
EURs, Economics and Well Designs Updated –
The Southern Marcellus division recently updated its EURs, economics and well designs for each of the three Marcellus areas in southwest Pennsylvania. These updated well designs incorporate reduced cluster spacing, longer laterals, improved lateral targeting in the reservoir and increased frac stages. All of these improvements are currently being implemented.
The following are highlights from the resulting changes in the updated development program. More details are provided in the most current Company Presentation found on Range’s website.
In the super-rich area of southwest Pennsylvania, Range is expecting:
| • | to drill average lateral lengths of 4,500 feet with 22 frac stages |
| • | the EUR to be 1.82 Mmboe per well (or 10.9 Bcfe per well) or 400 mboe per 1,000 feet of lateral (or 2.41 Bcfe on an equivalent basis for comparative purposes) |
In the wet area of southwest Pennsylvania Range is expecting:
| • | to drill average lateral lengths of 4,200 feet with 21 frac stages |
| • | the EUR to be 12.3 Bcfe or 2.93 Bcfe per 1,000 feet of lateral |
In the dry area of southwest Pennsylvania Range is expecting:
| • | to drill average lateral lengths of 5,000 feet with 25 frac stages |
| • | the EUR to be 12.2 Bcfe or 2.44 Bcfe per 1,000 feet of lateral |
Tighter Spacing Test Results Released –
Range announced the results of its three-year tighter spacing tests with 500 feet between laterals as compared to the historical 1,000 foot spacing between laterals currently used. These tests covered two different pads drilled in the super-rich and wet areas where both 1,000 foot spaced wells and 500 foot spaced wells were drilled on each pad in opposite directions or utilizing existing offsetting 1,000 foot spaced wells. After three years of production history, the production results indicate that wells drilled with 500 feet between horizontal laterals average approximately 80% of the estimated ultimate recoveries of horizontal wells drilled with 1,000 foot spacing between wells. The Company has released the comparative zero time plot production curves for the test wells in the Company’s updated presentation. The Company has increased its estimated unproved resource potential by an incremental 12 to 15 Tcfe in the wet and super-rich areas in the Marcellus as a result of the tighter spacing of 500 foot laterals. This additional resource potential brings Range’s total future unproved resource potential estimate to 60 to 83 Tcfe excluding any unproved resource potential for its Utica Shale acreage or tighter spacing in the dry gas areas in the Marcellus which Range also believes are prospective for 500 foot spacing.
Southern Marcellus Shale Division –
During the second quarter, the division brought online 45 Marcellus wells in southwest Pennsylvania, with 19 wells in the super-rich area, 15 wells in the wet area and 11 dry gas wells. Infrastructure build out remained on track during the quarter and Range started delivering ethane on July 21st for the initial commissioning of the Mariner West ethane pipeline to Sarnia, Canada. Range expects to deliver intermittently an average of 5,000 (4,175 net) barrels per day of ethane to the Mariner West pipeline during the second half of 2013 prior to full contract deliveries of 15,000 (12,525 net) barrels per day starting in early 2014. These initial ethane deliveries will also allow Range to meet pipeline quality specifications in southwest Pennsylvania.
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In the super-rich area of southwest Pennsylvania the division brought online 19 wells in the second quarter. The initial production rates of these super-rich wells averaged 1,863 (1,548 net) boe per day with 65% liquids (344 barrels condensate, 866 barrels NGLs and 3.9 Mmcf gas). All of the wells in the quarter were completed with reduced cluster spacing. The average lateral length for the wells was 3,686 feet and they averaged 18.8 frac stages per lateral. A six-well pad brought online early in the quarter had a 30-day average production rate per well of 1,037 (879 net) boe per day that was 69% liquids (160 barrels condensate, 556 barrels NGLs and 1.9 Mmcf gas). The higher initial production rates and higher expected recoveries are a result of improved lateral targeting and completion techniques that are now being applied across the super-rich and wet areas of the play. Future wells are expected to have an average lateral length of 4,500 feet and 22 frac stages.
Range also announced two super-rich wells with extraordinary 24-hour initial production rates that were turned to sales during July. The first well was drilled with a 4,115 foot lateral with 21 frac stages. The well tested at a peak 24-hour production rate into sales of 3,670 (3,046 net) boe per day with 72% liquids assuming 80% ethane extraction. The initial production rate includes 1,094 barrels of condensate per day, 1,540 barrels of NGLs per day and 6.2 Mmcf of gas per day. The second well had a peak 24-hour production rate into sales of 5,721 (4,748 net) boe per day with 63% liquids assuming 80% ethane extraction. The second well’s initial production rate was composed of 866 barrels per day of condensate, 2,727 barrels of NGLs per day and 12.8 Mmcf of gas per day. The second well was drilled with a 5,082 foot lateral and 26 frac stages. The pads are approximately ten miles apart.
In the wet area of southwest Pennsylvania the division brought online 15 wells in the second quarter. The initial production rates of these wet gas wells averaged 13.7 (11.5 net) Mmcfe per day with 38% liquids (8.5 Mmcf gas, 854 barrels NGLs and 16 barrels condensate). The average lateral length for these 15 wells was 2,627 feet and they averaged 13.5 frac stages per lateral, with 14 of the wells utilizing reduced cluster spacing. Twelve of the wet gas wells brought online in the second quarter have produced long enough to have a 30-day average of 7.5 (6.3 net) Mmcfe per day with 34% liquids (5.0 Mmcf gas, 425 barrels NGLs and 2 barrels condensate) despite being curtailed due to pipeline and plant constraints. Future wells are expected to have an average lateral length of 4,200 feet and 21 frac stages.
In the dry gas area of southwest Pennsylvania the division brought online 11 (9.6 net) wells during the second quarter. The initial production rates of these wells averaged 8.5 Mmcf per day with an average lateral length of 2,974 feet and an average of 14.4 frac stages per lateral. Future dry gas Marcellus wells in southwest Pennsylvania are expected to utilize longer laterals and additional frac stages with an average lateral length of 5,000 feet and 25 frac stages.
At quarter-end the division’s backlog of wells waiting on completion or pipeline connection decreased to 41 wells. Range expects to turn to sales a total of 103 wells in the southern Marcellus during 2013.
Northern Marcellus Shale Division –
In northeast Pennsylvania, Range brought online two wells in the second quarter, both in Lycoming County. These two wells produced at an average 24-hour production rate per well of 12.6 (10.7 net) Mmcf per day from an average lateral length of 3,342 feet with 10.5 frac stages. The division’s backlog of uncompleted wells and wells waiting on pipeline connection increased to 29 at quarter-end. Range anticipates drilling another eight wells and completing some of its backlog in northeast Pennsylvania during the remainder of 2013. The eight wells are expected to be drilled with laterals of 4,000 feet to 6,600 feet. Several wells expected to be drilled in early 2014 are designed with 6,500 foot to 7,000 foot laterals.
At the end of the second quarter, in the Bradford County area operated by Talisman, there were a total of 27 (7.9 net) wells producing and 36 (10.7 net) wells waiting on completion or pipeline connection.
In northwest Pennsylvania, Range continues to monitor offset Utica shale activity where the Company has approximately 181,000 net acres of leasehold prospective for liquids-rich Utica shale.
Midcontinent Division –
During the second quarter, the Midcontinent division continued to focus on Range’s horizontal Mississippian acreage along the Nemaha Ridge. The division tested smaller volume stimulation designs during late 2012 through part of the second quarter. Results were below expectations, so the division moved back to a larger volume. A total of 11 (10.1 net) wells were turned to sales during the quarter with average lateral lengths of 3,776 feet with 20 frac stages. The division has brought online 28 wells so far this year and the 30-day average IP rate per well is 346 (270 net) boe per day with 76% liquids.
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Notably, the division recently completed three wells with larger stimulations. One well was turned to production with a 24-hour initial production rate of 1,306 (788 net) boe per day that was 66% liquids (230 barrels oil, 629 barrels NGLs and 2,682 mcf gas) from a lateral of 4,288 feet with 20 frac stages. The second well was turned to sales with an initial 24-hour peak rate of 957 (788 net) boe per day that was 55% liquids (268 barrels oil, 258 barrels NGLs and 2,585 mcf gas) from a lateral of 3,615 feet with 20 stages. In the last few days, the third well’s 24-hour initial production rate was 1,116 (826 net) boe per day with 80% liquids (625 barrels oil, 287 barrels NGLs and 1,225 mcf gas) from a lateral of 4,265 feet with 23 frac stages. Results from the wells with the larger stimulations indicate that EURs are expected to be in the range of 485 – 600 Mboe per well. Range anticipates bringing online an additional 10 to 12 net Horizontal Mississippian wells by year-end using the larger stimulation design.
Range completed one operated St. Louis well during the quarter with a 24-hour initial production rate to sales of 8.3 (5.8 net) Mmcfe per day with 30% liquids. Earlier in the year, two additional operated wells with lower working interest were turned to sales with 24-hour initial production rates of 11.2 (1.9 net) Mmcfe per day and 5.3 (0.9 net) Mmcfe per day. In addition, Range expects to drill two to four more wells in that area by the end of 2013.
Permian Division –
Range’s Permian division drilled eight additional vertical Wolfberry test wells in the second quarter of 2013. Initial production rates based on 24-hour tests averaged 342 (270 net) boe per day with 80% liquids (193 barrels oil, 79 barrels NGLs and 423 mcf gas). In the Cline Shale, Range continues to monitor industry activity in an area where the Company has approximately 100,000 net acre position that is over 90% held by production.
Southern Appalachia Division –
The Southern Appalachia division continued development of multi-pay horizons on its 350,000 (250,000 net) acre position in Virginia during the second quarter of 2013. Range owns the fee minerals on 216,000 acres of this position and receives the added economic benefit of the royalty for wells drilled on this acreage. The division had two drilling rigs running in the quarter and drilled 12 wells including seven horizontal Huron Shale wells and five coalbed methane wells. The horizontal Huron wells set new records in Virginia for lateral length with two laterals over 4,500 feet. Four of these horizontals have been brought online with early average production rates being the best to date. The division turned online a total of 9 wells during the quarter.
Guidance –
Production Guidance:
Production growth for 2013 is targeted to the higher end of our 20% to 25% year-over-year guidance. Production for the third quarter of 2013 is expected to range between 945 to 950 Mmcfe per day. Liquids are expected to be approximately 22% of third quarter production. The Company has included in this guidance for the third quarter an average of 1,630 (1,360 net) barrels per day of ethane deliveries for the Mariner West pipeline commissioning process. These projected initial volumes may be subject to start up delays while commissioning the pipeline, ethane storage facilities and the cracker in Canada. The Company continues to expect to deliver on average 5,000 (4,175 net) barrels per day of ethane over the last six months of the year. Under the current contract arrangements, Range is scheduled to increase ethane deliveries under this first ethane arrangement to 15,000 barrels per day at the beginning of 2014. Because ethane deliveries are FOB the Houston processing plant, the Company is not expected to incur any additional costs associated with the contract and will record ethane sales as deliveries are made.
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Guidance for 2013 Activity:
Under the current plan, Range expects to turn to sales approximately 173 net wells in the Marcellus and Horizontal Mississippian during 2013, as shown below:
| Wells in First Half 2013 |
Remaining 2013 Wells |
Planned Total Wells to Sales in 2013 |
||||||||||
| Super-Rich area |
39 | 20 | 59 | |||||||||
| Wet area |
15 | 11 | 26 | |||||||||
| Dry area (NE & SW) |
28 | 21 | 49 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total Marcellus |
82 | 52 | 134 | |||||||||
| Hz. Mississippian |
28 | 11 | 39 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total |
110 | 63 | 173 | |||||||||
Expense per mcfe 3Q 2013 Guidance:
| Direct operating expense: |
$ | 0.38—$0.40 per mcfe | ||
| Transportation, gathering and compression expense: |
$ | 0.80—$0.82 per mcfe | ||
| Production tax expense: |
$ | 0.14—$0.15 per mcfe | ||
| Exploration expense: |
$ | 19—$21 million | ||
| Unproved property impairment expense: |
$ | 15—$17 million | ||
| G&A expense: |
$ | 0.40—$0.42 per mcfe | ||
| Interest expense: |
$ | 0.51—$0.52 per mcfe | ||
| DD&A expense: |
$ | 1.46—$1.48 per mcfe |
Differential Pricing History (a)
| 1Q 2012 | 2Q 2012 | 3Q 2012 | 4Q 2012 | 1Q 2013 | 2Q 2013 | |||||||||||||||||||
| Natural Gas |
($ | 0.02 | ) | ($ | 0.13 | ) | ($ | 0.03 | ) | $ | 0.18 | $ | 0.15 | $ | 0.04 | |||||||||
| NGL (% of WTI NYMEX) |
48 | % | 39 | % | 33 | % | 43 | % | 38 | % | 33 | % | ||||||||||||
| Oil (% of WTI NYMEX) |
88 | % | 91 | % | 90 | % | 89 | % | 90 | % | 89 | % | ||||||||||||
| (a) | Differentials based on pre-hedge pricing, excluding transportation, gathering and compression expense. |
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 75% of its expected remaining 2013 (third and fourth quarter) natural gas production hedged at a weighted average floor price of $4.18 per mcf. Similarly, Range has hedged more than 80% of its projected remaining crude oil production at a floor price of $94.80 and more than 50% of its composite NGL production near current market prices. 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 July 1, 2013, the Company expects to reclassify into earnings $49.5 million of unrealized net gains frozen in the first quarter with discontinuance of hedge accounting in the remaining six months of 2013 and $10.9 million of unrealized net gains in 2014.
Conference Call Information
A conference call to review the financial results is scheduled on Thursday, July 25 at 11:00 a.m. ET. To participate in the call, please dial 877-407-0778 and ask for the Range Resources second quarter 2013 financial results conference call. A replay of the call will be available through August 25. To access the phone replay dial 877-660-6853. The conference ID is 417201.
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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 August 25.
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.
Second quarter 2013 earnings included a gain of $159.5 million for the non-cash unrealized mark-to-market increase in value of the Company’s derivatives, a gain of $83.3 million primarily for sale of the New Mexico properties closed on April 1, unproved property impairment expense of $19.2 million, a $6.9 million gain recorded for the mark-to-market in the deferred compensation plan, a $52.9 million expense primarily for settlement of a class action lawsuit concerning alleged deductions from prices used to calculate royalties paid to royalty owners in certain Oklahoma wells in prior years, and $15.4 million of non-cash stock compensation expenses. Excluding these and other items, net income would have been $55.0 million or $0.34 per diluted share. Excluding similar non-cash items from the prior-year quarter, net income would have been $18.1 million or $0.11 per diluted share. By excluding these non-cash items from our reported earnings, we believe we present our earnings in a manner consistent with the presentation used by analysts in their projection of the Company’s earnings. (See the reconciliation of non-GAAP earnings in the accompanying table.)
Cash flow from operations before changes in working capital 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.
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.
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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/ and http://www.myrangeresources.com/.
All statements, except for statements of historical fact, made in this release regarding activities, events or developments the Company expects, believes or anticipates will or may occur in the future, such as those regarding future growth in production, low-reinvestment risk, earnings and per-share value, improved well performance, expected greater capital efficiency, future rates of return, continued drilling improvements, capital spending plans, disproportionate growth in liquids production, cost structure improvements, reduction in operating costs, sole access to facilities, reserves in stacked reservoirs, resolution of pipeline quality requirements, planned exports, expected drilling and development plans, future guidance information, technical progress, estimated ethane volumes, progress in liquid-rich areas, unproved resource potential, continued improvements, growth objectives, future low cost structure, EURs, estimated capital to drill and complete wells and superior economics 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 actual 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 being actually 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 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
8
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.
In addition, our production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. 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.
2013-18
SOURCE: Range Resources Corporation
Investor Contacts:
Rodney Waller, Senior Vice President
817-869-4258
David Amend, Investor Relations Manager
817-869-4266
Laith Sando, Research Manager
817-869-4267
Michael Freeman, Financial Analyst
817-869-4264
or
Media Contact:
Matt Pitzarella, Director of Corporate Communications
724-873-3224
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 June 30, | Six Months Ended June 30, | |||||||||||||||||||||||
| 2013 | 2012 | % | 2013 | 2012 | % | |||||||||||||||||||
| Revenues and other income: |
||||||||||||||||||||||||
| Natural gas, NGLs and oil sales (a) |
$ | 437,678 | $ | 298,349 | $ | 835,917 | $ | 615,966 | ||||||||||||||||
| Derivative cash settlements gain (loss) (a) (b) |
(21,767 | ) | 12,198 | (21,385 | ) | 4,369 | ||||||||||||||||||
| Change in mark-to-market on unrealized derivatives gain (loss) (b) |
159,371 | 135,777 | 62,569 | 83,721 | ||||||||||||||||||||
| Ineffective hedging (loss) gain (b) |
155 | 594 | (3,300 | ) | (354 | ) | ||||||||||||||||||
| Gain (loss) on sale of properties |
83,287 | (3,227 | ) | 83,121 | (13,653 | ) | ||||||||||||||||||
| Brokered natural gas and marketing |
14,404 | 5,406 | 35,462 | 8,681 | ||||||||||||||||||||
| Equity method investment (c) |
353 | 501 | 273 | 817 | ||||||||||||||||||||
| Other (c) |
(125 | ) | (667 | ) | (62 | ) | 339 | |||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total revenues and other income |
673,356 | 448,931 | 50 | % | 992,595 | 699,886 | 42 | % | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Costs and expenses: |
||||||||||||||||||||||||
| Direct operating |
31,940 | 26,349 | 61,467 | 55,014 | ||||||||||||||||||||
| Direct operating – non-cash stock compensation (d) |
696 | 692 | 1,357 | 1,049 | ||||||||||||||||||||
| Transportation, gathering and compression |
66,048 | 44,744 | 128,464 | 85,564 | ||||||||||||||||||||
| Production and ad valorem taxes |
11,113 | 11,079 | 22,496 | 23,713 | ||||||||||||||||||||
| Pennsylvania impact fee —prior year |
— | 707 | — | 24,707 | ||||||||||||||||||||
| Brokered natural gas and marketing |
16,132 | 6,083 | 38,198 | 9,692 | ||||||||||||||||||||
| Brokered natural gas and marketing – non-cash stock-based compensation (d) |
530 | 408 | 779 | 861 | ||||||||||||||||||||
| Exploration |
12,108 | 14,523 | 27,818 | 35,111 | ||||||||||||||||||||
| Exploration – non-cash stock compensation (d) |
960 | 994 | 2,030 | 1,922 | ||||||||||||||||||||
| Abandonment and impairment of unproved properties |
19,156 | 43,641 | 34,374 | 63,930 | ||||||||||||||||||||
| General and administrative |
35,607 | 30,565 | 70,961 | 60,620 | ||||||||||||||||||||
| General and administrative – non-cash stock compensation (d) |
13,263 | 12,540 | 23,569 | 20,698 | ||||||||||||||||||||
| General and administrative – lawsuit settlements |
52,867 | 900 | 91,265 | 1,416 | ||||||||||||||||||||
| General and administrative – bad debt expense |
250 | — | 250 | — | ||||||||||||||||||||
| Deferred compensation plan (e) |
(6,878 | ) | 9,333 | 35,482 | 1,503 | |||||||||||||||||||
| Interest expense |
45,071 | 42,888 | 87,281 | 80,093 | ||||||||||||||||||||
| Loss on early extinguishment of debt |
12,280 | — | 12,280 | — | ||||||||||||||||||||
| Depletion, depreciation and amortization |
119,995 | 108,802 | 235,096 | 208,953 | ||||||||||||||||||||
| Impairment of proved properties and other assets |
741 | — | 741 | — | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total costs and expenses |
431,879 | 354,248 | 22 | % | 873,908 | 674,846 | 29 | % | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Income from continuing operations before income taxes |
241,477 | 94,683 | 155 | % | 118,687 | 25,040 | 374 | % | ||||||||||||||||
| Income tax expense (benefit): |
||||||||||||||||||||||||
| Current |
(25 | ) | — | — | — | |||||||||||||||||||
| Deferred |
97,519 | 39,007 | 50,314 | 11,164 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| 97,494 | 39,007 | 50,314 | 11,164 | |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Net income |
$ | 143,983 | $ | 55,676 | 159 | % | $ | 68,373 | $ | 13,876 | 393 | % | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Income Per Common Share: |
||||||||||||||||||||||||
| Basic |
$ | 0.88 | $ | 0.34 | $ | 0.42 | $ | 0.09 | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Diluted |
$ | 0.88 | $ | 0.34 | $ | 0.42 | $ | 0.09 | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Weighted average common shares outstanding, as reported: |
||||||||||||||||||||||||
| Basic |
160,565 | 159,412 | 1 | % | 160,346 | 159,162 | 1 | % | ||||||||||||||||
| Diluted |
161,414 | 160,030 | 1 | % | 161,223 | 159,949 | 1 | % | ||||||||||||||||
| (a) | See separate natural gas, NGLs and oil sales information table. |
| (b) | Included in Derivative fair value income in the 10-Q. |
| (c) | Included in Brokered natural gas, marketing and other revenues in the 10-Q. |
| (d) | 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. |
| (e) | Reflects the change in market value of the vested Company stock held in the deferred compensation plan. |
10
RANGE RESOURCES CORPORATION
BALANCE SHEETS
| June 30, 2013 |
December 31, 2012 |
|||||||
| (In thousands) | (Unaudited) | (Audited) | ||||||
| Assets |
||||||||
| Current assets |
$ | 176,396 | $ | 190,062 | ||||
| Current unrealized derivatives |
97,052 | 137,552 | ||||||
| Natural gas and oil properties |
6,333,791 | 6,096,184 | ||||||
| Transportation and field assets |
36,207 | 41,567 | ||||||
| Other |
286,736 | 263,370 | ||||||
|
|
|
|
|
|||||
| $ | 6,930,182 | $ | 6,728,735 | |||||
|
|
|
|
|
|||||
| Liabilities and Stockholders’ Equity |
||||||||
| Current liabilities |
$ | 502,010 | $ | 448,202 | ||||
| Current asset retirement obligation |
2,366 | 2,470 | ||||||
| Current unrealized derivatives |
— | 4,471 | ||||||
| Bank debt |
309,000 | 739,000 | ||||||
| Subordinated notes |
2,639,835 | 2,139,185 | ||||||
|
|
|
|
|
|||||
| 2,948,835 | 2,878,185 | |||||||
|
|
|
|
|
|||||
| Deferred tax liability |
735,166 | 698,302 | ||||||
| Unrealized derivatives |
— | 3,463 | ||||||
| Deferred compensation liability |
207,906 | 187,604 | ||||||
| Long-term asset retirement obligation and other |
148,116 | 148,646 | ||||||
|
|
|
|
|
|||||
| 1,091,188 | 1,038,015 | |||||||
| Common stock and retained earnings |
2,352,646 | 2,278,243 | ||||||
| Treasury stock |
(3,751 | ) | (4,760 | ) | ||||
| Accumulated other comprehensive income |
36,888 | 83,909 | ||||||
|
|
|
|
|
|||||
| Total stockholders’ equity |
2,385,783 | 2,357,392 | ||||||
|
|
|
|
|
|||||
| $ | 6,930,182 | $ | 6,728,735 | |||||
|
|
|
|
|
|||||
11
RANGE RESOURCES CORPORATION
CASH FLOWS FROM OPERATING ACTIVITIES
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| (Unaudited, in thousands) | 2013 | 2012 | 2013 | 2012 | ||||||||||||
| Net income (loss) |
$ | 143,983 | $ | 55,676 | $ | 68,373 | $ | 13,876 | ||||||||
| Adjustments to reconcile net cash provided from continuing operations: |
||||||||||||||||
| (Gain) loss from equity investment, net of distributions |
(2,162 | ) | 2,042 | (1,552 | ) | 2,293 | ||||||||||
| Deferred income tax expense (benefit) |
97,519 | 39,007 | 50,314 | 11,164 | ||||||||||||
| Depletion, depreciation, amortization and proved property impairment |
120,736 | 108,802 | 235,837 | 208,953 | ||||||||||||
| Exploration dry hole costs |
— | 108 | (159 | ) | 817 | |||||||||||
| Abandonment and impairment of unproved properties |
19,156 | 43,641 | 34,374 | 63,930 | ||||||||||||
| Mark-to-market (gain) loss on oil and gas derivatives not designated as hedges |
(159,371 | ) | (135,777 | ) | (62,569 | ) | (83,721 | ) | ||||||||
| Unrealized derivatives (gain) loss |
(155 | ) | (594 | ) | 3,300 | 354 | ||||||||||
| Allowance for bad debts |
250 | — | 250 | — | ||||||||||||
| Amortization of deferred issuance costs, loss on extinguishment of debt, and other |
14,582 | 2,045 | 16,662 | 3,893 | ||||||||||||
| Deferred and stock-based compensation |
8,334 | 23,833 | 63,325 | 26,341 | ||||||||||||
| Gain (loss) on sale of assets and other |
(83,287 | ) | 3,227 | (83,121 | ) | 13,653 | ||||||||||
| Changes in working capital: |
||||||||||||||||
| Accounts receivable |
(15,289 | ) | (336 | ) | (13,997 | ) | 11,611 | |||||||||
| Inventory and other |
1,379 | (1,927 | ) | 1,545 | (2,824 | ) | ||||||||||
| Accounts payable |
(16,156 | ) | (30,884 | ) | (10,381 | ) | (21,922 | ) | ||||||||
| Accrued liabilities and other |
(50,879 | ) | 18,106 | (22,312 | ) | 34,528 | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net changes in working capital |
(80,945 | ) | (15,041 | ) | (45,145 | ) | 21,393 | |||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net cash provided from operating activities |
$ | 78,640 | $ | 126,969 | $ | 279,889 | $ | 282,946 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
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 June 30, | Six Months Ended June 30, | |||||||||||||||
| (Unaudited, in thousands) | 2013 | 2012 | 2013 | 2012 | ||||||||||||
| Net cash provided from operating activities, as reported |
$ | 78,640 | $ | 126,969 | $ | 279,889 | $ | 282,946 | ||||||||
| Net changes in working capital from continuing operations |
80,945 | 15,041 | 45,145 | (21,393 | ) | |||||||||||
| Exploration expense |
12,108 | 14,415 | 27,977 | 34,294 | ||||||||||||
| Lawsuit settlements |
52,867 | 900 | 91,265 | 1,416 | ||||||||||||
| Equity method investment distribution / intercompany elimination |
1,809 | (2,544 | ) | 1,278 | (3,110 | ) | ||||||||||
| Prior year Pennsylvania impact fee |
— | 707 | — | 24,707 | ||||||||||||
| Non-cash compensation adjustment |
247 | 245 | 41 | (143 | ) | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Cash flow from operations before changes in working capital, a non-GAAP measure |
$ | 226,616 | $ | 155,733 | $ | 445,595 | $ | 318,717 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING |
|
|||||||||||||||
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| (Unaudited, in thousands) | 2013 | 2012 | 2013 | 2012 | ||||||||||||
| Basic: |
||||||||||||||||
| Weighted average shares outstanding |
163,211 | 162,325 | 163,027 | 162,031 | ||||||||||||
| Stock held by deferred compensation plan |
(2,646 | ) | (2,913 | ) | (2,681 | ) | (2,869 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Adjusted basic |
160,565 | 159,412 | 160,346 | 159,162 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Dilutive: |
||||||||||||||||
| Weighted average shares outstanding |
163,211 | 162,325 | 163,027 | 162,031 | ||||||||||||
| Dilutive stock options under treasury method |
(1,797 | ) | (2,295 | ) | (1,804 | ) | (2,082 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Adjusted dilutive |
161,414 | 160,030 | 161,223 | 159,949 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
RECONCILIATION OF TOTAL REVENUES AND OTHER
INCOME TO TOTAL REVENUE EXCLUDING CERTAIN
ITEMS, a non-GAAP measure
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||
| (Unaudited, in thousands) | 2013 | 2012 | % | 2013 | 2012 | % | ||||||||||||||||||
| Total revenues and other income, as reported |
$ | 673,356 | $ | 448,931 | 50 | % | $ | 992,595 | $ | 699,886 | 42 | % | ||||||||||||
| Adjustment for certain special items: |
||||||||||||||||||||||||
| Change in mark-to-market on unrealized derivative (gain) loss |
(159,371 | ) | (135,777 | ) | (62,569 | ) | (83,721 | ) | ||||||||||||||||
| Ineffective hedging (gain) loss |
(155 | ) | (594 | ) | 3,300 | 354 | ||||||||||||||||||
| (Gain) loss on sale of properties |
(83,287 | ) | 3,227 | (83,121 | ) | 13,653 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total revenues, as adjusted, non-GAAP |
$ | 430,543 | $ | 315,787 | 36 | % | $ | 850,205 | $ | 630,172 | 35 | % | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
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 June 30, | Six Months Ended June 30, | |||||||||||||||||||||||
| (Unaudited, in thousands, except per unit data) | 2013 | 2012 | % | 2013 | 2012 | % | ||||||||||||||||||
| Natural gas, NGLs and oil sales components: |
||||||||||||||||||||||||
| Natural gas sales |
$ | 272,720 | $ | 111,413 | $ | 526,665 | $ | 239,481 | ||||||||||||||||
| NGLs sales |
66,587 | 56,280 | 134,158 | 132,778 | ||||||||||||||||||||
| Oil sales |
73,562 | 52,075 | 151,562 | 107,497 | ||||||||||||||||||||
| Cash-settled hedges (effective): |
||||||||||||||||||||||||
| Natural gas |
24,694 | 78,896 | 23,315 | 136,525 | ||||||||||||||||||||
| Crude oil |
115 | (315 | ) | 217 | (315 | ) | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total natural gas, NGLs and oil sales, as reported |
$ | 437,678 | $ | 298,349 | 47 | % | $ | 835,917 | $ | 615,966 | 36 | % | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Derivative fair value income (loss) components: |
||||||||||||||||||||||||
| Cash-settled derivatives (ineffective): |
||||||||||||||||||||||||
| Natural gas |
$ | (24,698 | ) | $ | 1,278 | $ | (23,319 | ) | $ | 2,463 | ||||||||||||||
| NGLs |
3,043 | 10,152 | 2,148 | 5,760 | ||||||||||||||||||||
| Crude Oil |
(111 | ) | 768 | (213 | ) | (3,854 | ) | |||||||||||||||||
| Change in mark-to-market on unrealized derivatives |
159,371 | 135,777 | 62,569 | 83,721 | ||||||||||||||||||||
| Unrealized ineffectiveness |
155 | 594 | (3,300 | ) | (354 | ) | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total derivative fair value income (loss), as reported |
$ | 137,760 | $ | 148,569 | $ | 37,885 | $ | 87,736 | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Natural gas, NGLs and oil sales, including all cash-settled derivatives (c): |
||||||||||||||||||||||||
| Natural gas sales |
$ | 272,716 | $ | 191,587 | $ | 526,661 | $ | 378,469 | ||||||||||||||||
| NGL sales |
69,630 | 66,432 | 136,306 | 138,538 | ||||||||||||||||||||
| Oil sales |
73,566 | 52,528 | 151,566 | 103,328 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total |
$ | 415,912 | $ | 310,547 | 34 | % | $ | 814,533 | $ | 620,335 | 31 | % | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Third party transportation, gathering and compression fee components: |
||||||||||||||||||||||||
| Natural gas |
$ | 62,754 | $ | 42,168 | $ | 121,995 | $ | 80,674 | ||||||||||||||||
| NGLs |
3,294 | 2,576 | 6,469 | 4,890 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total transportation, gathering and compression, as reported |
$ | 66,048 | $ | 44,744 | $ | 128,464 | $ | 85,564 | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Production during the period (a): |
||||||||||||||||||||||||
| Natural gas (mcf) |
64,926,278 | 52,293,227 | 24 | % | 126,950,234 | 98,926,434 | 28 | % | ||||||||||||||||
| NGLs (bbl) |
2,115,489 | 1,570,593 | 35 | % | 4,004,913 | 3,131,419 | 28 | % | ||||||||||||||||
| Oil (bbl) |
864,517 | 623,026 | 39 | % | 1,777,179 | 1,231,103 | 44 | % | ||||||||||||||||
| Gas equivalent (mcfe) (b) |
82,806,314 | 65,454,941 | 27 | % | 161,642,786 | 125,101,566 | 29 | % | ||||||||||||||||
| Production – average per day (a): |
||||||||||||||||||||||||
| Natural gas (mcf) |
713,476 | 574,651 | 24 | % | 701,383 | 543,552 | 29 | % | ||||||||||||||||
| NGLs (bbl) |
23,247 | 17,259 | 35 | % | 22,127 | 17,206 | 29 | % | ||||||||||||||||
| Oil (bbl) |
9,500 | 6,846 | 39 | % | 9,819 | 6,764 | 45 | % | ||||||||||||||||
| Gas equivalent (mcfe) (b) |
909,959 | 719,285 | 27 | % | 893,054 | 687,371 | 30 | % | ||||||||||||||||
| Average prices, including cash-settled hedges and derivatives before third party transportation costs: |
||||||||||||||||||||||||
| Natural gas (mcf) |
$ | 4.20 | $ | 3.66 | 15 | % | $ | 4.15 | $ | 3.83 | 8 | % | ||||||||||||
| NGLs (bbl) |
$ | 32.91 | $ | 42.30 | -22 | % | $ | 34.03 | $ | 44.24 | -23 | % | ||||||||||||
| Oil (bbl) |
$ | 85.09 | $ | 84.31 | 1 | % | $ | 85.28 | $ | 83.93 | 2 | % | ||||||||||||
| Gas equivalent (mcfe) (b) |
$ | 5.02 | $ | 4.74 | 6 | % | $ | 5.04 | $ | 4.96 | 2 | % | ||||||||||||
| Average prices, including cash-settled hedges and derivatives (d): |
||||||||||||||||||||||||
| Natural gas (mcf) |
$ | 3.23 | $ | 2.86 | 13 | % | $ | 3.19 | $ | 3.01 | 6 | % | ||||||||||||
| NGLs (bbl) |
$ | 31.36 | $ | 40.66 | -23 | % | $ | 32.42 | $ | 42.68 | -24 | % | ||||||||||||
| Oil (bbl) |
$ | 85.09 | $ | 84.31 | 1 | % | $ | 85.28 | $ | 83.93 | 2 | % | ||||||||||||
| Gas equivalent (mcfe) (b) |
$ | 4.23 | $ | 4.06 | 4 | % | $ | 4.24 | $ | 4.27 | -1 | % | ||||||||||||
| Transportation, gathering and compression expense per mcfe |
$ | 0.80 | $ | 0.68 | 17 | % | $ | 0.79 | $ | 0.68 | 16 | % | ||||||||||||
| (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 economic 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
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||
| (Unaudited, in thousands, except per share data) | 2013 | 2012 | % | 2013 | 2012 | % | ||||||||||||||||||
| Income from continuing operations before income taxes, as reported |
$ | 241,477 | $ | 94,683 | 155 | % | $ | 118,687 | $ | 25,040 | 374 | % | ||||||||||||
| Adjustment for certain special items: |
||||||||||||||||||||||||
| Gain (loss) on sale of properties |
(83,287 | ) | 3,227 | (83,121 | ) | 13,653 | ||||||||||||||||||
| Change in mark-to-market on unrealized derivatives (gain) loss |
(159,371 | ) | (135,777 | ) | (62,569 | ) | (83,721 | ) | ||||||||||||||||
| Unrealized derivative (gain) loss |
(155 | ) | (594 | ) | 3,300 | 354 | ||||||||||||||||||
| Abandonment and impairment of unproved properties |
19,156 | 43,641 | 34,374 | 63,930 | ||||||||||||||||||||
| Loss on early extinguishment of debt |
12,280 | — | 12,280 | — | ||||||||||||||||||||
| Prior year Pennsylvania impact fee |
— | 707 | — | 24,707 | ||||||||||||||||||||
| Proved property and other asset impairment |
741 | — | 741 | — | ||||||||||||||||||||
| Lawsuit settlements |
52,867 | 900 | 91,265 | 1,416 | ||||||||||||||||||||
| Brokered natural gas and marketing – non cash stock-based compensation |
|
530 |
|
|
408 |
|
|
779 |
|
|
861 |
|
||||||||||||
| Direct operating – non-cash stock-based compensation |
696 | 692 | 1,357 | 1,049 | ||||||||||||||||||||
| Exploration expenses – non-cash stock-based compensation |
960 | 994 | 2,030 | 1,922 | ||||||||||||||||||||
| General & administrative – non-cash stock-based compensation |
13,263 | 12,540 | 23,569 | 20,698 | ||||||||||||||||||||
| Deferred compensation plan – non-cash adjustment |
(6,878 | ) | 9,333 | 35,482 | 1,503 | |||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Income from operations before income taxes, as adjusted |
92,279 | 30,754 | 200 | % | 178,174 | 71,412 | 150 | % | ||||||||||||||||
| Income tax expense, as adjusted |
||||||||||||||||||||||||
| Current |
(25 | ) | — | — | — | |||||||||||||||||||
| Deferred |
37,273 | 12,668 | 70,266 | 28,912 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Net income excluding certain items, a non-GAAP measure |
$ | 55,031 | $ | 18,086 | 204 | % | $ | 107,908 | $ | 42,500 | 154 | % | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Non-GAAP income per common share |
||||||||||||||||||||||||
| Basic |
$ | 0.34 | $ | 0.11 | 209 | % | $ | 0.67 | $ | 0.27 | 148 | % | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Diluted |
$ | 0.34 | $ | 0.11 | 209 | % | $ | 0.67 | $ | 0.27 | 148 | % | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Non-GAAP diluted shares outstanding, if dilutive |
161,414 | 160,030 | 161,223 | 159,949 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
HEDGING POSITION AS OF JULY 24, 2013 –
(Unaudited)
| Daily Volume | Hedge Price | |||||||
| Gas (Mmbtu) |
||||||||
| 3Q 2013 Swaps |
300,000 | $ | 3.75 | |||||
| 3Q 2013 Collars |
280,000 | $ | 4.59—$5.05 | |||||
| 4Q 2013 Swaps |
293,370 | $ | 3.82 | |||||
| 4Q 2013 Collars |
280,000 | $ | 4.59—$5.05 | |||||
| 2014 Swaps |
30,000 | $ | 4.17 | |||||
| 2014 Collars |
447,500 | $ | 3.84—$4.48 | |||||
| 2015 Collars |
145,000 | $ | 4.07—$4.56 | |||||
| Oil (Bbls) |
||||||||
| 3Q 2013 Swaps |
5,825 | $ | 96.74 | |||||
| 3Q 2013 Collars |
3,000 | $ | 90.60—$100.00 | |||||
| 4Q 2013 Swaps |
6,825 | $ | 96.79 | |||||
| 4Q 2013 Collars |
3,000 | $ | 90.60—$100.00 | |||||
| 2014 Swaps |
7,000 | $ | 94.14 | |||||
| 2014 Collars |
2,000 | $ | 85.55—$100.00 | |||||
| 2015 Swaps |
2,000 | $ | 90.20 | |||||
| C5 Natural Gasoline (Bbls) |
|
|||||||
| 3Q 2013 Swaps |
6,500 | $ | 2.134 | |||||
| 4Q 2013 Swaps |
6,500 | $ | 2.134 | |||||
| C3 Propane (Bbls) |
||||||||
| 3Q 2013 Swaps |
9,326 | $ | 0.940 | |||||
| 4Q 2013 Swaps |
10,000 | $ | 0.941 | |||||
| 2014 Swaps |
1,000 | $ | 0.960 | |||||
14
NOTE: SEE WEBSITE FOR OTHER SUPPLEMENTAL INFORMATION FOR THE PERIODS
15