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 28, 2015 (April 28, 2015)
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, 2015 Range Resources Corporation issued a press release announcing its first quarter 2015 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, 2015 |
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 28, 2015 | ||||||
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EXHIBIT INDEX
| Exhibit |
Description | |
| 99.1 | Press Release dated April 28, 2015 | |
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Exhibit 99.1
NEWS RELEASE
RANGE ANNOUNCES FIRST QUARTER 2015 RESULTS
FORT WORTH, TEXAS, APRIL 28, 2015…RANGE RESOURCES CORPORATION (NYSE: RRC) today announced its first quarter financial results.
Highlights –
| • | Production volumes reached a record high, averaging 1,328 Mmcfe per day, a 26% increase over the prior-year quarter. |
| • | Unit costs declined $0.53 per mcfe, or 15% compared to the prior-year. |
| • | Washington County Marcellus well brought on line in late April with a 24-hour production rate of 43.4 Mmcfe per day. This is a new record and the highest rate ever for any Marcellus well. |
| • | Record Utica well has cumulative production to date of 1.2 Bcf under constrained conditions. |
| • | New well in dry gas area of Washington County, Pennsylvania brought on line in first quarter at a 24-hour production rate of 31.3 Mmcf per day. |
| • | An additional long-term LNG sales agreement signed, bringing total LNG sales agreements to 200,000 Mmbtu per day. |
Commenting, Jeff Ventura, Range’s Chairman, President and CEO, said, “First quarter operational results continue to be excellent, as we exceeded our first quarter production guidance and we continue to see great drilling results with lower cost and improved capital efficiency in the Marcellus. The oversupply of natural gas and NGLs in Appalachia have created a challenging price environment, but we see signs of improvement coming, and until then, our hedges help to improve financial results. Later this year, the Mariner East project is expected to commence, providing Range another premium outlet for ethane sales, plus substantial savings on propane transportation costs.
With our current plan to spend approximately $700 million less in 2015 than 2014 and still target 20% growth, we believe that we will be one of the most capital efficient companies in our industry. This continuing capital efficiency, coupled with our large footprint in the core of the Marcellus, Utica and Upper Devonian, with optionality of drilling dry, wet and super-rich acreage, gives Range flexibility to maximize returns. Combined with the shape of our 20% growth profile in 2015, which is back-end loaded, we are well positioned for the remainder of 2015, 2016 and beyond.”
Operational Discussion
Range has updated its investor presentation. Please see www.rangeresources.com under the “Investors” tab, “Company Presentations” area, for the presentation entitled, “Company Presentation - April 28, 2015.”
Southern Marcellus Shale Division –
Production for the first quarter averaged 887 net Mmcfe per day for the division, a 32% increase over the prior year. The division’s first quarter net production included 490 Mmcf per day of gas, 55,786 barrels per day of NGLs and 10,382 barrels per day of condensate. During the first quarter, the division brought on line 35 wells in southwest Pennsylvania, with 17 wells in the super-rich area, 14 wells in the wet gas area, three Marcellus dry gas wells and one Utica dry gas well. For Marcellus wells brought on line in the first quarter, the average working interest was 98%, and the average net revenue interest was 82%.
During the first quarter, the division brought on line the Claysville’s Sportsman’s Club Unit #11H, the division’s first Washington County Utica well that tested at an initial 24-hour rate of 59 Mmcf per day in late December. The well was brought on line in late January, at a constrained rate of 20 Mmcf per day on an interruptible basis.
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To date, production results are encouraging, as the well has cumulative production of 1.2 Bcf of gas. Production results and formation analysis continue to reinforce the Company’s belief that the well is located in the core of the Utica with the highest gas in place. Range has an 87.5% working interest and a net revenue interest of 71.1% in this well. The division plans two additional Utica wells in 2015, with the first well spud recently and the other well planned to spud in the second half of this year. Range holds approximately 400,000 net acres, considered prospective for Utica dry gas.
Late in the quarter, the division brought on line a well in the dry gas area of Washington County that produced under constrained conditions at a 24-hour production rate of 31.3 Mmcf per day. The well was drilled with a lateral length of 7,906 feet and 41 stages. Two additional wells are planned for this pad in the second quarter.
Also, in late April, a well brought on line in the wet gas area of Washington County set a record for any Marcellus well drilled to date, with an initial 24-hour production rate to sales of 43.4 Mmcfe per day. The well was drilled with a lateral length of 8,668 feet containing 45 stages, and is producing under constrained conditions.
Northern Marcellus Shale Division –
In northeast Pennsylvania, production for the first quarter averaged 253 net Mmcf per day for the division, a 30% increase over the prior year. In the first quarter, the division turned three wells to sales, with an average working interest of 100% and average net revenue interest of 84%. One well brought on line had an initial 24-hour rate to sales of 26.1 Mmcf per day, with a 30-day average rate of 21 Mmcf per day and a 60-day rate of 19 Mmcf per day. Range anticipates 2015 rig activity to fluctuate between one and two rigs in order to satisfy the drilling obligations on larger leases, and turning 11 wells to sales for the remainder of 2015.
Southern Appalachia Division –
Production for the first quarter averaged 107 net Mmcf per day for the division, a 53% increase over the prior year, primarily due to the increased volumes resulting from the Nora/Conger exchange with EQT, completed in June 2014. Production was negatively impacted by the cold weather during the first quarter. The division continues to test new completion techniques and well designs, which have so far produced impressive results. Because of these improvements, coalbed methane (“CBM”) wells completed in 2014 and first quarter 2015 are the best group of CBM wells in over 20 years at Nora. Importantly, the Virginia assets receive a premium gas price due to their strategic location near the growing southeast markets along the Atlantic Coast.
Marcellus Shale Marketing, Transportation and Processing Update –
As part of the commissioning process on the Sunoco Mariner East pipeline, Range began flowing propane in late 2014, in advance of the announced in-service date for the Marcus Hook harbor facilities in third quarter of 2015. When the project is fully operational, Range expects savings of approximately $0.20 per gallon on the 20,000 barrels per day of propane contracted on the Mariner East pipeline, and expects to initiate sales of 20,000 barrels per day of ethane under its long-term export agreement with INEOS. Range is expecting $90 million of additional annualized cash flow from its NGL transportation and sales arrangements when Mariner East is fully operational.
In addition, Range recently signed a long-term LNG sales agreement with an international purchaser for 50,000 Mmbtu per day, resulting in total signed LNG sales agreements of 200,000 Mmbtu per day. Range will be utilizing its existing firm capacity agreements to supply gas under all of these LNG sales agreements.
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Financial Discussion
(Except for generally accepted accounting principles (“GAAP”) reported amounts, specific expense categories exclude non-cash impairments, derivative fair value income/(loss), non-cash stock compensation and other items shown separately on the attached tables. “Total 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. “Total unit cash costs” are the same as “Total unit costs”, except exclude depletion, depreciation and amortization costs. 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 2015 totaled $463 million (a 1% increase as compared to first quarter 2014), GAAP net cash provided from operating activities including changes in working capital reached $211 million and GAAP earnings were $27.7 million ($0.16 per diluted share) versus earnings of $32.5 million ($0.20 per diluted share) in the prior-year quarter. First quarter 2015 results included $123 million in derivative gains due to decreased commodity prices, compared to a $147 million loss in the first quarter of 2014. First quarter 2015 results also included a $5.6 million gain in the deferred compensation plan due to decreases in the Company’s stock price compared to a gain of $2.0 million in first quarter 2014.
Non-GAAP revenues for first quarter 2015 totaled $437 million (a 13% decrease compared to first quarter 2014) and cash flow from operations before changes in working capital, a non-GAAP measure, was $207 million. Adjusted net income comparable to analysts’ estimates, a non-GAAP measure, was $30.9 million ($0.19 per diluted share for the first quarter 2015), compared to $74.1 million ($0.46 per diluted share) in the prior year. The Company’s total unit cash costs of $1.77 per mcfe in first quarter 2015 decreased by $0.41 per mcfe or 19% compared to the prior-year quarter. The Company’s total unit costs in first quarter 2015 decreased by $0.53 per mcfe or 15% compared to the prior-year quarter.
First quarter 2015 natural gas, NGLs and oil price realizations (including the impact of cash-settled hedges and derivative settlements which correspond to analysts’ estimates) averaged $3.54 per mcfe, a 28% decrease from the prior-year quarter. Additional detail on commodity price realizations can be found in the Supplemental Tables provided on the Company’s website.
| • | Production and realized prices for each commodity for the first quarter of 2015 were: natural gas – 894 Mmcf per day ($3.54 per mcf), NGLs – 59,548 barrels per day ($12.20 per barrel) and crude oil and condensate – 12,655 barrels per day ($64.06 per barrel). |
| • | The first quarter average natural gas price decreased to $3.54 per mcf (including the impact of cash-settled hedges), as compared to the prior-year quarter of $4.20 per mcf. Financial hedges based upon NYMEX increased realizations $0.79 per mcf while financial basis hedges decreased realizations $0.10 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, equal to the prior year differential. |
| • | NGL pricing, before hedges, but net of processing and transportation costs, was 23% of the West Texas Intermediate index (“WTI”) for the first quarter compared to 31% of WTI in the prior-year quarter, and 25% of WTI in the fourth quarter of 2014. |
| • | Crude oil and condensate price realizations, before hedges, for the first quarter averaged $16.19 below WTI compared to $13.48 below WTI in the prior-year quarter. Crude oil and condensate realizations, before hedges, for fourth quarter 2014 were $15.08 below WTI. |
Capital Expenditures
First quarter drilling expenditures of $262 million funded the drilling and recompletion of 35 (31 net) wells. A 100% drilling success rate was achieved. In addition, during the first quarter, $13.4 million was expended on acreage, $2.2 million on gas gathering systems and $7.2 million for exploration expense. The Company is on
7
track with its 2015 capital expenditure budget of $870 million, as first quarter expenditures did not fully reflect the impact of service cost declines announced in late February. We expect to see those decreases reflected fully in the second quarter and beyond.
Financial Position and Liquidity
As previously announced on March 31, Range’s existing $3 billion borrowing base and $2 billion commitment amount under its $4 billion bank credit facility were unanimously reaffirmed by its 29 bank lending group. Under the terms of the credit agreement, the borrowing base will be renewed annually, with the current borrowing base in effect through May 1, 2016. The facility has a maximum amount of $4 billion and matures in October 2019. The debt to EBITDAX covenant of 4.25x, was replaced with an EBITDAX to interest expense covenant of 2.5x. The ratio of the present value of proved reserves to total debt covenant of 1.5x will apply until Range has two investment grade ratings.
Guidance – Second Quarter 2015
Production Guidance:
Production growth for 2015 is targeted at 20% year-over-year. Average daily production for the second quarter of 2015 is expected to be 1.345 Bcfe per day, with 30% liquids.
Expense per mcfe Guidance:
| Direct operating expense: |
$0.30 - $0.32 per mcfe | |
| Transportation, gathering and compression expense: |
$0.75 - $0.77 per mcfe | |
| Production tax expense: |
$0.08 - $0.09 per mcfe | |
| Exploration expense: |
$ 10 - 12 million | |
| Unproved property impairment expense: |
$ 12 - 14 million | |
| G&A expense: |
$0.31 - $0.33 per mcfe | |
| Interest expense: |
$0.33 - $0.34 per mcfe | |
| DD&A expense: |
$1.23 - $1.25 per mcfe |
Based on historical trends, base net expense for brokered natural gas and marketing activity is expected to be $4 million net expense per quarter.
Guidance for 2015 Activity:
Estimated 2015 well costs for several areas below are summarized on page 17 in the current investor presentation, titled “Company Presentation - April 28, 2015”, located on the Range website at www.rangeresources.com, and include the effect of estimated service cost declines announced in late February. Average lateral lengths for Marcellus wells in 2015 are expected to increase compared to 2014, averaging over 6,000 feet.
Under the current plan, which is subject to change during the year, Range expects to turn to sales approximately 150 wells during 2015, as shown below:
| Wells turned to sales - First Quarter 2015 |
Remaining 2015 Wells to sales |
Planned Total Wells to sales in 2015 |
||||||||||
| Super-Rich area |
17 | 9 | 26 | |||||||||
| Wet area |
14 | 26 | 40 | |||||||||
| Dry- SW |
4 | 33 | 37 | |||||||||
| Dry- NE |
3 | 11 | 14 | |||||||||
|
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|
|
|
|
|
|||||||
| Total Marcellus/Utica |
38 | 79 | 117 | |||||||||
| Nora area |
6 | 19 | 25 | |||||||||
| Midcontinent |
6 | 2 | 8 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total |
50 | 100 | 150 | |||||||||
|
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|
|
|
|
|||||||
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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 85% of its remaining 2015 natural gas production hedged at a weighted average floor price of $3.77 per Mmbtu. Similarly, Range has hedged more than 85% of its remaining 2015 projected crude oil production at a floor price of $ 87.44 per barrel and over half of its remaining composite NGL production.
For calendar year 2016, Range has hedged 622,500 Mmbtu per day of its expected natural gas production at a weighted average price of $3.42 per Mmbtu and has started hedging 2017 gas volumes. Similarly, Range has hedged 3,000 barrels per day of its 2016 projected crude oil production at an average price of $70.54 per barrel and 10,500 barrels per day of its expected NGL production. Please see Range’s detailed hedging schedule posted at the end of the financial tables below and on its website at www.rangeresources.com.
Basis Hedging Status
In addition to the collars and swaps above, at March 31, 2015, we had natural gas basis swap contracts which lock in the differential between NYMEX and certain of our physical pricing indices, primarily in Appalachia. These contracts settle monthly through March 2017 and the volumes are for 44,070,000 Mmbtu. The fair value of these contracts was a liability of $1.4 million at March 31, 2015.
Conference Call Information
A conference call to review the financial results is scheduled on Wednesday, April 29 at 9:00 a.m., Eastern time. To participate in the call, please dial 877-407-0778 and ask for the Range Resources first quarter 2015 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 13605782.
A simultaneous webcast of the call may be accessed over the Internet at 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 and 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.
9
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.
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 Income 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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RANGE RESOURCES CORPORATION (NYSE: RRC) is a leading independent oil and natural gas producer with operations focused in Appalachia and the Midcontinent 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 regarding activities, events or developments the Company expects, believes or anticipates will or may occur in the future, such as those regarding future liquidity, production growth, completion of ethane projects, estimated gas in place, future rates of return, future low costs, low reinvestment risk, future earnings and per-share value, future capital spending plans, increasing capital efficiency, well-positioned, continued utilization of existing infrastructure, gas marketability, maximized realized natural gas prices, acreage quality, access to multiple gas markets, expected drilling and development plans, improved capital efficiency, future financial position, future technical improvements, future marketing opportunities 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 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,” “unrisked resource potential,” “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 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 and completion services and equipment, lease expirations, transportation constraints, regulatory approvals, field spacing rules, recoveries of gas in place, length of horizontal laterals, actual drilling and completion 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.
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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 on the SEC’s website at www.sec.gov or by calling the SEC at 1-800-SEC-0330.
2015-07
| 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, Senior 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 | ||
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RANGE RESOURCES CORPORATION
STATEMENTS OF INCOME
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, | ||||||||||||
| 2015 | 2014 | % | ||||||||||
| Revenues and other income: |
||||||||||||
| Natural gas, NGLs and oil sales (a) |
$ | 325,483 | $ | 572,017 | ||||||||
| Derivative fair value income/(loss) |
122,839 | (146,850 | ) | |||||||||
| Loss on sale of assets |
(175 | ) | (353 | ) | ||||||||
| Brokered natural gas, marketing and other (b) |
14,433 | 33,249 | ||||||||||
| Equity method investment (b) |
— | (133 | ) | |||||||||
| ARO settlement loss (b) |
(2 | ) | (659 | ) | ||||||||
| Other (b) |
54 | 71 | ||||||||||
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|||||||||
| Total revenues and other income |
462,632 | 457,342 | 1 | % | ||||||||
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|||||||||
| Costs and expenses: |
||||||||||||
| Direct operating |
36,251 | 38,943 | ||||||||||
| Direct operating – non-cash stock-based compensation (c) |
886 | 852 | ||||||||||
| Transportation, gathering and compression |
89,426 | 74,161 | ||||||||||
| Production and ad valorem taxes |
9,928 | 11,678 | ||||||||||
| Brokered natural gas and marketing |
21,056 | 33,601 | ||||||||||
| Brokered natural gas and marketing – non-cash stock- based compensation (c) |
506 | 528 | ||||||||||
| Exploration |
7,154 | 13,693 | ||||||||||
| Exploration – non-cash stock-based compensation (c) |
732 | 1,153 | ||||||||||
| Abandonment and impairment of unproved properties |
11,491 | 9,995 | ||||||||||
| General and administrative |
36,663 | 37,200 | ||||||||||
| General and administrative – non-cash stock-based compensation (c) |
11,080 | 11,604 | ||||||||||
| General and administrative – lawsuit settlements |
336 | 408 | ||||||||||
| General and administrative – bad debt expense |
250 | — | ||||||||||
| Termination costs |
4,663 | — | ||||||||||
| Termination costs – non-cash stock-based compensation (c) |
1,287 | — | ||||||||||
| Deferred compensation plan (d) |
(5,624 | ) | (2,035 | ) | ||||||||
| Interest expense |
39,207 | 45,401 | ||||||||||
| Depletion, depreciation and amortization |
147,290 | 128,682 | ||||||||||
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|||||||||
| Total costs and expenses |
412,582 | 405,864 | 2 | % | ||||||||
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|||||||||
| Income before income taxes |
50,050 | 51,478 | 3 | % | ||||||||
| Income tax expense |
||||||||||||
| Current |
— | 6 | ||||||||||
| Deferred |
22,366 | 18,951 | ||||||||||
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| 22,366 | 18,957 | |||||||||||
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| Net income |
$ | 27,684 | $ | 32,521 | -15 | % | ||||||
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| Net Income Per Common Share: |
||||||||||||
| Basic |
$ | 0.16 | $ | 0.20 | ||||||||
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| Diluted |
$ | 0.16 | $ | 0.20 | ||||||||
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|||||||||
| Weighted average common shares outstanding, as reported: |
||||||||||||
| Basic |
166,039 | 160,794 | 3 | % | ||||||||
| Diluted |
166,066 | 161,825 | 3 | % | ||||||||
| (a) | See separate natural gas, NGLs and oil sales information table. |
| (b) | Included in Brokered natural gas, marketing and other revenues in the 10-Q. |
| (c) | Costs associated with stock compensation and restricted stock amortization, which have been reflected in the categories associated with the direct personnel costs, and are combined with the cash costs in the 10-Q. |
| (d) | Reflects the change in market value of the vested Company stock held in the deferred compensation plan. |
13
RANGE RESOURCES CORPORATION
BALANCE SHEETS
(In thousands)
| March 31, 2015 |
December 31, 2014 |
|||||||
| (Unaudited) | (Audited) | |||||||
| Assets |
||||||||
| Current assets |
$ | 152,095 | $ | 207,243 | ||||
| Derivative assets |
358,544 | 363,049 | ||||||
| Natural gas and oil properties, successful efforts method |
8,105,982 | 7,977,573 | ||||||
| Transportation and field assets |
34,978 | 37,581 | ||||||
| Other |
193,288 | 161,334 | ||||||
|
|
|
|
|
|||||
| $ | 8,844,887 | $ | 8,746,780 | |||||
|
|
|
|
|
|||||
| Liabilities and Stockholders’ Equity |
||||||||
| Current liabilities |
$ | 592,474 | $ | 740,197 | ||||
| Asset retirement obligations |
17,689 | 15,067 | ||||||
| Derivative liabilities |
1,142 | — | ||||||
| Bank debt |
912,000 | 723,000 | ||||||
| Subordinated notes |
2,350,000 | 2,350,000 | ||||||
|
|
|
|
|
|||||
| 3,262,000 | 3,073,000 | |||||||
|
|
|
|
|
|||||
| Deferred tax liability |
1,014,250 | 997,494 | ||||||
| Deferred compensation liability |
173,134 | 178,599 | ||||||
| Asset retirement obligations and other liabilities |
294,742 | 284,994 | ||||||
|
|
|
|
|
|||||
| 1,482,126 | 1,461,087 | |||||||
| Common stock and retained earnings |
3,492,218 | 3,460,517 | ||||||
| Common stock held in treasury stock |
(2,762 | ) | (3,088 | ) | ||||
|
|
|
|
|
|||||
| Total stockholders’ equity |
3,489,456 | 3,457,429 | ||||||
|
|
|
|
|
|||||
| $ | 8,844,887 | $ | 8,746,780 | |||||
|
|
|
|
|
|||||
RECONCILIATION OF TOTAL REVENUES AND
OTHER INCOME TO TOTAL REVENUE EXCLUDING
CERTAIN ITEMS, a non-GAAP measure
(Unaudited, in thousands)
| Three Months Ended March 31, | ||||||||||||
| 2015 | 2014 | % | ||||||||||
| Total revenues and other income, as reported |
$ | 462,632 | $ | 457,342 | 1 | % | ||||||
| Adjustment for certain special items: |
||||||||||||
| Total change in fair value related to derivatives prior to settlement (gain) loss |
(25,349 | ) | 42,266 | |||||||||
| ARO settlement loss |
2 | 659 | ||||||||||
| Loss on sale of assets |
175 | 353 | ||||||||||
|
|
|
|
|
|||||||||
| Total revenues, as adjusted, non-GAAP |
$ | 437,460 | $ | 500,620 | -13 | % | ||||||
|
|
|
|
|
|||||||||
14
RANGE RESOURCES CORPORATION
CASH FLOWS FROM OPERATING ACTIVITIES
(Unaudited, in thousands)
| Three Months Ended March 31, |
||||||||
| 2015 | 2014 | |||||||
| Net income |
$ | 27,684 | $ | 32,521 | ||||
| Adjustments to reconcile net income to cash provided from continuing operations: |
||||||||
| Loss from equity investment, net of distributions |
— | 2,732 | ||||||
| Deferred income tax expense |
22,366 | 18,951 | ||||||
| Depletion, depreciation, amortization and impairment |
147,290 | 128,682 | ||||||
| Exploration dry hole and impairment costs |
103 | 1 | ||||||
| Abandonment and impairment of unproved properties |
11,491 | 9,995 | ||||||
| Derivative fair value (income) loss |
(122,839 | ) | 146,850 | |||||
| Cash settlements on derivative financial instruments that do not qualify for hedge accounting |
97,490 | (104,584 | ) | |||||
| Allowance for bad debts |
250 | — | ||||||
| Amortization of deferred issuance costs, loss on extinguishment of debt and other |
1,358 | 2,873 | ||||||
| Deferred and stock-based compensation |
9,218 | 12,593 | ||||||
| Loss on sale of assets and other |
175 | 353 | ||||||
| Changes in working capital: |
||||||||
| Accounts receivable |
54,435 | (41,643 | ) | |||||
| Inventory and other |
(1,072 | ) | (5,358 | ) | ||||
| Accounts payable |
7,098 | 9,997 | ||||||
| Accrued liabilities and other |
(44,409 | ) | (32,742 | ) | ||||
|
|
|
|
|
|||||
| Net changes in working capital |
16,052 | (69,746 | ) | |||||
|
|
|
|
|
|||||
| Net cash provided from operating activities |
$ | 210,638 | $ | 181,221 | ||||
|
|
|
|
|
|||||
RECONCILIATION OF NET CASH PROVIDED FROM OPERATING
ACTIVITIES, AS REPORTED, TO CASH FLOW FROM OPERATIONS BEFORE
CHANGES IN WORKING CAPITAL, a non-GAAP measure
(Unaudited, in thousands)
| Three Months Ended March 31, |
||||||||
| 2015 | 2014 | |||||||
| Net cash provided from operating activities, as reported |
$ | 210,638 | $ | 181,221 | ||||
| Net changes in working capital |
(16,052 | ) | 69,746 | |||||
| Exploration expense |
7,051 | 13,692 | ||||||
| Lawsuit settlements |
336 | 408 | ||||||
| Equity method investment distribution / intercompany elimination |
— | (2,599 | ) | |||||
| Termination costs |
4,663 | — | ||||||
| Non-cash compensation adjustment |
(103 | ) | (366 | ) | ||||
|
|
|
|
|
|||||
| Cash flow from operations before changes in working capital – a non-GAAP measure |
$ | 206,533 | $ | 262,102 | ||||
|
|
|
|
|
|||||
|
ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING
(Unaudited, in thousands) |
||||||||
| Three Months Ended March 31, |
||||||||
| 2015 | 2014 | |||||||
| Basic: |
||||||||
| Weighted average shares outstanding |
168,861 | 163,609 | ||||||
| Stock held by deferred compensation plan |
(2,822 | ) | (2,815 | ) | ||||
|
|
|
|
|
|||||
| Adjusted basic |
166,039 | 160,794 | ||||||
|
|
|
|
|
|||||
| Dilutive: |
||||||||
| Weighted average shares outstanding |
168,861 | 163,609 | ||||||
| Dilutive stock options under treasury method |
(2,795 | ) | (1,784 | ) | ||||
|
|
|
|
|
|||||
| Adjusted dilutive |
166,066 | 161,825 | ||||||
|
|
|
|
|
|||||
15
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
(Unaudited, in thousands, except per unit data)
| Three Months Ended March 31, | ||||||||||||
| 2015 | 2014 | % | ||||||||||
| Natural gas, NGL and oil sales components: |
||||||||||||
| Natural gas sales |
$ | 228,740 | $ | 346,226 | ||||||||
| NGL sales |
59,811 | 135,504 | ||||||||||
| Oil sales |
36,932 | 88,121 | ||||||||||
| Cash-settled hedges (effective): |
||||||||||||
| Natural gas |
— | 1,168 | ||||||||||
| Crude oil |
— | 998 | ||||||||||
|
|
|
|
|
|||||||||
| Total oil and gas sales, as reported |
$ | 325,483 | $ | 572,017 | -43 | % | ||||||
|
|
|
|
|
|||||||||
| Derivative fair value income (loss), as reported: |
$ | 122,839 | $ | (146,850 | ) | |||||||
| Cash settlements on derivative financial instruments – (gain) loss: |
||||||||||||
| Natural gas |
(55,869 | ) | 87,108 | |||||||||
| NGLs |
(5,595 | ) | 13,272 | |||||||||
| Crude Oil |
(36,026 | ) | 4,204 | |||||||||
|
|
|
|
|
|||||||||
| Total change in fair value related to derivatives prior to settlement, a non GAAP measure |
$ | 25,349 | $ | (42,266 | ) | |||||||
|
|
|
|
|
|||||||||
| Transportation, gathering and compression components: |
||||||||||||
| Natural gas |
$ | 76,527 | $ | 65,299 | ||||||||
| NGLs |
12,899 | 8,862 | ||||||||||
|
|
|
|
|
|||||||||
| Total transportation, gathering and compression, as reported |
$ | 89,426 | $ | 74,161 | ||||||||
|
|
|
|
|
|||||||||
| Natural gas, NGL and oil sales, including cash-settled derivatives: (c) |
||||||||||||
| Natural gas sales |
$ | 284,609 | $ | 260,286 | ||||||||
| NGL sales |
65,406 | 122,232 | ||||||||||
| Oil sales |
72,958 | 84,915 | ||||||||||
|
|
|
|
|
|||||||||
| Total |
$ | 422,973 | $ | 467,433 | -10 | % | ||||||
|
|
|
|
|
|||||||||
| Production of oil and gas during the periods (a): |
||||||||||||
| Natural gas (mcf) |
80,500,036 | 62,017,581 | 30 | % | ||||||||
| NGL (bbl) |
5,359,276 | 4,471,481 | 20 | % | ||||||||
| Oil (bbl) |
1,138,960 | 1,035,145 | 10 | % | ||||||||
| Gas equivalent (mcfe) (b) |
119,489,452 | 95,057,337 | 26 | % | ||||||||
| Production of oil and gas – average per day (a): |
||||||||||||
| Natural gas (mcf) |
894,445 | 689,084 | 30 | % | ||||||||
| NGL (bbl) |
59,548 | 49,683 | 20 | % | ||||||||
| Oil (bbl) |
12,655 | 11,502 | 10 | % | ||||||||
| Gas equivalent (mcfe) (b) |
1,327,661 | 1,056,193 | 26 | % | ||||||||
| Average prices, including cash-settled hedges that qualify for hedge accounting before third party transportation costs: |
||||||||||||
| Natural gas (mcf) |
$ | 2.84 | $ | 5.60 | -49 | % | ||||||
| NGL (bbl) |
$ | 11.16 | $ | 30.30 | -63 | % | ||||||
| Oil (bbl) |
$ | 32.43 | $ | 86.09 | -62 | % | ||||||
| Gas equivalent (mcfe) (b) |
$ | 2.72 | $ | 6.02 | -55 | % | ||||||
| Average prices, including cash-settled hedges and derivatives before third party transportation costs: (c) |
||||||||||||
| Natural gas (mcf) |
$ | 3.54 | $ | 4.20 | -16 | % | ||||||
| NGL (bbl) |
$ | 12.20 | $ | 27.34 | -55 | % | ||||||
| Oil (bbl) |
$ | 64.06 | $ | 82.03 | -22 | % | ||||||
| Gas equivalent (mcfe) (b) |
$ | 3.54 | $ | 4.92 | -28 | % | ||||||
| Average prices, including cash-settled hedges and derivatives: (d) |
||||||||||||
| Natural gas (mcf) |
$ | 2.58 | $ | 3.14 | -18 | % | ||||||
| NGL (bbl) |
$ | 9.80 | $ | 25.35 | -61 | % | ||||||
| Oil (bbl) |
$ | 64.06 | $ | 82.03 | -22 | % | ||||||
| Gas equivalent (mcfe) (b) |
$ | 2.79 | $ | 4.14 | -33 | % | ||||||
| Transportation, gathering and compression expense per mcfe |
$ | 0.75 | $ | 0.78 | -4 | % | ||||||
| (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 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. |
16
RANGE RESOURCES CORPORATION
RECONCILIATION OF INCOME 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, | ||||||||||||
| 2015 | 2014 | % | ||||||||||
| Income (loss) before income taxes, as reported |
$ | 50,050 | $ | 51,478 | 3 | % | ||||||
| Adjustment for certain special items: |
||||||||||||
| Loss on sale of assets |
175 | 353 | ||||||||||
| Loss on ARO settlements |
2 | 659 | ||||||||||
| Change in fair value related to derivatives prior to settlement |
(25,349 | ) | 42,266 | |||||||||
| Abandonment and impairment of unproved properties |
11,491 | 9,995 | ||||||||||
| Lawsuit settlements |
336 | 408 | ||||||||||
| Termination costs |
4,663 | — | ||||||||||
| Termination costs – non-cash stock-based compensation |
1,287 | — | ||||||||||
| Brokered natural gas and marketing – non-cash stock-based compensation |
506 | 528 | ||||||||||
| Direct operating – non-cash stock-based compensation |
886 | 852 | ||||||||||
| Exploration expenses – non-cash stock-based compensation |
732 | 1,153 | ||||||||||
| General & administrative – non-cash stock-based compensation |
11,080 | 11,604 | ||||||||||
| Deferred compensation plan – non-cash adjustment |
(5,624 | ) | (2,035 | ) | ||||||||
|
|
|
|
|
|||||||||
| Income before income taxes, as adjusted |
50,235 | 117,261 | -57 | % | ||||||||
| Income tax expense, as adjusted |
||||||||||||
| Current |
— | 6 | ||||||||||
| Deferred |
19,299 | 43,179 | ||||||||||
|
|
|
|
|
|||||||||
| Net income excluding certain items, a non-GAAP measure |
$ | 30,936 | $ | 74,076 | -58 | % | ||||||
|
|
|
|
|
|||||||||
| Non-GAAP income per common share |
||||||||||||
| Basic |
$ | 0.19 | $ | 0.46 | -59 | % | ||||||
|
|
|
|
|
|||||||||
| Diluted |
$ | 0.19 | $ | 0.46 | -59 | % | ||||||
|
|
|
|
|
|||||||||
| Non-GAAP diluted shares outstanding, if dilutive |
166,066 | 161,825 | ||||||||||
|
|
|
|
|
|||||||||
17
RANGE RESOURCES CORPORATION
HEDGING POSITION AS OF APRIL 24, 2015 –
(Unaudited)
| Daily Volume | Hedge Price | |||
| Gas |
||||
| 2Q 2015 Swaps |
737,500 Mmbtu | $3.63 | ||
| 2Q 2015 Collars |
145,000 Mmbtu | $4.07 - $4.56 | ||
| 3Q 2015 Swaps |
737,500 Mmbtu | $3.64 | ||
| 3Q 2015 Collars |
145,000 Mmbtu | $4.07 - $4.56 | ||
| 4Q 2015 Swaps |
717,500 Mmbtu | $3.64 | ||
| 4Q 2015 Collars |
145,000 Mmbtu | $4.07 $4.56 | ||
| 2016 Swaps |
622,500 Mmbtu | $3.42 | ||
| 2017 Swaps |
20,000 Mmbtu | $3.49 | ||
| Oil |
||||
| 2Q 2015 Swaps |
9,500 bbls | $90.58 | ||
| 3Q 2015 Swaps |
11,250 bbls | $85.87 | ||
| 4Q 2015 Swaps |
11,250 bbls | $85.87 | ||
| 2016 Swaps |
3,000 bbls | $70.54 | ||
| C3 Propane |
||||
| 2Q 2015 Swaps |
14,000 bbls | $0.65/gallon | ||
| 3Q 2015 Swaps |
14,000 bbls | $0.61/gallon | ||
| 4Q 2015 Swaps |
12,000 bbls | $0.55/gallon | ||
| 2016 Swaps |
5,500 bbls | $0.60/gallon | ||
| C4 Normal Butane | ||||
| 2Q 2015 Swaps |
3,500 bbls | $0.72/gallon | ||
| 3Q 2015 Swaps |
3,500 bbls | $0.72/gallon | ||
| 4Q 2015 Swaps |
3,500 bbls | $0.72/gallon | ||
| 2016 Swaps |
2,500 bbls | $0.72/gallon | ||
| C5 Natural Gasoline | ||||
| 2Q 2015 Swaps |
3,500 bbls | $1.14/gallon | ||
| 3Q 2015 Swaps |
4,000 bbls | $1.16/gallon | ||
| 4Q 2015 Swaps |
4,000 bbls | $1.16/gallon | ||
| 2016 Swaps |
2,500 bbls | $1.23/gallon | ||
NOTE: SEE WEBSITE FOR OTHER SUPPLEMENTAL INFORMATION FOR THE PERIODS
18