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): February 25, 2016
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 February 25, 2016 Range Resources Corporation issued a press release announcing its 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 February 25, 2016
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: February 25, 2016
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EXHIBIT INDEX
| Exhibit |
Description | |
| 99.1 | Press Release dated February 25, 2016 | |
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Exhibit 99.1
RANGE REPORTS 2015 EARNINGS, ANNOUNCES 2016 CAPITAL PLANS
FORT WORTH, TEXAS, FEBRUARY 25, 2016…RANGE RESOURCES CORPORATION (NYSE: RRC) today announced its 2015 financial results.
Highlights –
| • | Fourth quarter unit costs reduced by 15%, or $0.46 per mcfe compared to prior-year quarter |
| • | Fourth quarter natural gas differential improved $0.20, or 35%, compared to prior-year quarter, driven by additional takeaway projects |
| • | Record annual average daily production of 1.4 Bcfe per day |
| • | Reserve replacement of 436% at $0.37 per mcfe drill-bit finding cost |
| • | Peer-leading Marcellus EURs and well costs on a normalized lateral length basis |
| • | Completed Nora asset sale for cash proceeds of $865 million, used to reduce debt at year-end |
| • | Mariner East in final commissioning phase, expected to improve NGL netbacks |
| • | Signed agreement to sell Bradford County non-operated interest for approximately $112 million |
| • | 2016 capital budget set at $495 million; within expected cash flow and anticipated 2016 asset sales |
Commenting, Jeff Ventura, the Company’s CEO said, “Range continued to perform well operationally during the fourth quarter, despite the challenges from declining commodity prices. We will continue to focus on reducing costs, high-grading our operations and staying disciplined financially. At the end of December, we closed the sale of our Nora properties with cash proceeds of $865 million reducing debt. The sale accomplished several objectives: reducing leverage, increasing liquidity, high-grading the portfolio and reducing operating and overhead costs. Additionally, we recently signed an agreement to sell our non-operated Bradford County Marcellus interest for approximately $112 million and are currently marketing our central Oklahoma properties.
“As a result of excellent well performance, reduced capital and operating costs and improved differentials across all products, Range continues to achieve accretive returns on our Marcellus acreage. We have set our 2016 capital budget at $495 million, a 45% reduction compared to 2015 capital expenditures. This capital budget is aligned with expected 2016 cash flow plus anticipated proceeds from 2016 asset sales. Although we cannot be certain when prices will recover, we believe Range’s relative netbacks will continue to improve with Mariner East, Uniontown to Gas City and other projects that move products to new markets. With our high quality, low-cost asset base, Range is well-positioned to not only persevere, but add shareholder value in 2016.”
Financial Discussion
(Except for generally accepted accounting principles (“GAAP”) reported amounts, specific expense categories exclude non-cash impairments, unrealized mark-to-market on derivatives, non-cash stock compensation and other items shown separately on the attached tables. “Unit costs” as used in this release are composed of direct operating, transportation, gathering and compression, production and ad valorem taxes, general and administrative, interest and depletion, depreciation and amortization costs divided by production. See “Non-GAAP Financial Measures” for a definition of each of the non-GAAP financial measures and the tables that reconcile each of the non-GAAP measures to their most directly comparable GAAP financial measure.)
Full Year 2015
GAAP revenues for 2015 totaled $1.6 billion (34% decrease compared to 2014), GAAP net cash provided from operating activities including changes in working capital reached $684 million (28% decrease compared to 2014) and GAAP earnings were a loss of $714 million ($4.29 per diluted share) versus $634 million of earnings ($3.79 per diluted share) in 2014. Full year 2015 results included a loss of $407 million from asset sales compared to a gain of $286 million in 2014, $416 million in derivative gains due to decreases in future commodity prices compared to a $384 million gain in the prior year and a $590 million impairment of non-Marcellus proved property compared to $28 million in the prior year.
Non-GAAP revenues for 2015 totaled $1.7 billion (14% decrease compared to 2014), cash flow from operations before changes in working capital, a non-GAAP measure, reached $740 million (29% decrease compared to 2014). Adjusted net income
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comparable to analysts’ estimates, a non-GAAP measure, was $80 million ($0.48 per diluted share, a 70% decrease from 2014). The Company’s cost structure continued to improve as total unit costs decreased by $0.42 per mcfe, or 13%, compared to the prior year, as shown below.
| Expenses |
Full Year 2015 (per mcfe) |
Full Year 2014 (per mcfe) |
Increase (Decrease) |
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| Direct operating |
$ | 0.26 | $ | 0.34 | (24 | )% | ||||||
| Transportation, gathering and compression |
0.78 | 0.77 | 1 | % | ||||||||
| Production and ad valorem taxes |
0.07 | 0.11 | (36 | )% | ||||||||
| General and administrative |
0.27 | 0.35 | (23 | )% | ||||||||
| Interest expense |
0.33 | 0.40 | (18 | )% | ||||||||
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| Total cash unit costs |
1.71 | 1.97 | (13 | )% | ||||||||
| Depletion, depreciation and amortization |
1.14 | 1.30 | (12 | )% | ||||||||
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| Total unit costs |
$ | 2.85 | $ | 3.27 | (13 | )% | ||||||
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The Company announced its full year 2015 natural gas, NGLs and oil price realizations (including the impact of cash-settled hedges and derivative settlements which correspond to analysts’ estimates) averaged $3.18 per mcfe, a 28% composite decrease from the prior year. Additional detail on commodity price realizations can be found in the Supplemental Tables provided on the Company’s website.
| • | Production and realized prices by each commodity for 2015 were: natural gas – 994 Mmcf per day ($3.07 per mcf), NGLs – 55,770 barrels per day ($10.73 per barrel) and crude oil and condensate – 11,189 barrels per day ($71.28 per barrel). |
| • | The 2015 average natural gas price, before all hedging settlements, decreased to $2.13 per mcf as compared to $3.99 per mcf in the prior year. NYMEX natural gas financial hedges increased realizations $0.94 per mcf for 2015. The average Company natural gas price differential including the impact of basis hedging was ($0.52) per mcf compared to ($0.48) per mcf in the prior year. |
| • | Total NGL pricing per barrel including ethane and processing expenses after realized cash-settled hedging was $10.73 per barrel compared to $24.31 in the prior year. Hedging increased NGL prices by $2.06 per barrel in 2015 compared to $0.72 in the prior year. |
| • | Crude oil and condensate price realizations, before hedges, for the year averaged $34.28 per barrel, or $14.93 below West Texas Intermediate (“WTI”), compared to $14.84 below WTI in the prior year. Hedging added $37.00 per barrel in 2015 as hedging gains offset substantially lower oil prices, compared to hedge gains of $1.95 per barrel in the prior year. |
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Fourth Quarter 2015
GAAP revenues for the fourth quarter of 2015 totaled $411 million (53% decrease compared to fourth quarter 2014), GAAP net cash provided from operating activities including changes in working capital was $168 million (a 44% decrease as compared to fourth quarter 2014) and GAAP earnings were a loss of $322 million ($1.93 per diluted share) versus earnings of $284 million ($1.68 per diluted share) in the prior-year quarter. Fourth quarter 2015 results included a $409 million loss on sale of assets, while 2014 included a gain of $4 million. Fourth quarter 2015 also included $126 million in derivative gains due to decreased commodity prices, compared to a $412 million gain in 2014 and $88 million impairment of proved property compared to $3 million in the prior year.
Non-GAAP revenues for fourth quarter 2015 totaled $456 million (12% decrease compared to fourth quarter 2014), cash flow from operations before changes in working capital, a non-GAAP measure, reached $204 million. Adjusted net income comparable to analysts’ estimates, a non-GAAP measure, was $42 million ($0.25 per diluted share for the fourth quarter 2015). The Company’s total unit costs decreased by $0.46 per mcfe, or 15%, compared to the prior-year quarter, as shown below
| Expenses |
4Q 2015 (per mcfe) |
4Q 2014 (per mcfe) |
Increase (Decrease) |
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| Direct operating |
$ | 0.22 | $ | 0.32 | (31 | )% | ||||||
| Transportation, gathering and compression |
0.85 | 0.76 | 12 | % | ||||||||
| Production and ad valorem taxes |
0.06 | 0.10 | (40 | )% | ||||||||
| General and administrative |
0.22 | 0.33 | (33 | )% | ||||||||
| Interest expense |
0.31 | 0.33 | (6 | )% | ||||||||
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| Total cash unit costs |
1.66 | 1.84 | (10 | )% | ||||||||
| Depletion, depreciation and amortization |
0.97 | 1.25 | (22 | )% | ||||||||
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| Total unit costs |
$ | 2.63 | $ | 3.09 | (15 | )% | ||||||
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Fourth 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 $3.22 per mcfe, a 22% composite 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 by each commodity for fourth quarter 2015 were: natural gas – 1,056 Mmcf per day ($3.08 per mcf), NGLs – 53,333 barrels per day ($11.23 per barrel) and crude oil and condensate – 9,751 barrels per day ($79.62 per barrel). |
| • | The fourth quarter average natural gas price, before all hedging settlements, decreased to $1.89 per mcf as compared to $3.24 per mcf in the prior year. NYMEX natural gas financial hedges increased realizations $1.18 per mcf in the fourth quarter of 2015. The average Company natural gas price differential including the impact of basis hedges for the fourth quarter improved to ($0.37) per mcf compared to ($0.57) per mcf in the prior year. |
| • | Total NGL pricing per barrel including ethane and processing expenses after realized cash-settled hedging was $11.23 for the fourth quarter compared to $23.33 per barrel in the prior year. Hedging increased NGL prices by $2.12 per barrel in the fourth quarter compared to $5.37 per barrel in the prior year. |
| • | Crude oil and condensate price realizations, before realized hedges, for the fourth quarter averaged $28.70 per barrel, or $13.52 below WTI, compared to $15.08 below WTI in the prior year. Hedging added $50.92 per barrel compared to $19.67 in the prior year, as hedging offset substantially lower oil prices. |
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Financial Position and Liquidity
During 2015, Range decreased total debt by $378 million to $2.7 billion. In May 2015, Range issued $750 million of 4.875% Senior Notes due 2025. The Company subsequently called for redemption, in August, of all $500 million in outstanding principal of its 6.75% Senior Subordinated notes due in 2020, significantly reducing its borrowing costs and extending the average maturity of its debt. As a result, interest expense for the year was $3 million lower than 2014. On December 30, Range closed on the sale of its Nora assets, using the proceeds to reduce debt, which is expected to further reduce interest expense in 2016. Total debt consists of long-term notes of $2.6 billion and $95 million outstanding under the Company’s credit facility. The Company’s long-term notes have staggered maturities not starting until 2021. The Company’s revolving credit facility borrowing base remained unchanged at $3 billion following the Nora sale with a committed amount of $2 billion.
Range’s senior subordinated notes include a provision that potentially limits the amount of total debt the Company can incur under its revolving credit facility. The calculation is based on SEC commodity prices and the PV10 discounted future cash flows of proved reserves at each year-end. Based on the year-end 2015 PV10 discounted value, Range’s ability to draw on the credit facility is currently limited to a $1.5 billion floor for 2016. Therefore, liquidity under the revolving credit facility using this threshold as of December 31, 2015 was $1.3 billion.
Range’s Board of Directors also declared a quarterly cash dividend on the Company’s common stock for the first quarter 2016. A dividend of $0.02 per share, is payable on March 31, 2016 to stockholders of record at the close of business on March 15, 2016. This represents a 50% reduction from the previous $0.04 per share. The reduced dividend will provide approximately $13.6 million of additional cash flow on an annualized basis.
In early February, Range signed a purchase and sale agreement covering its non-operating Marcellus interest in Bradford County for approximately $112 million. The average working interest of 23% covers approximately 10,900 net acres with net production of approximately 22 Mmcf per day. Range received a deposit in connection with the signed agreement and expects the sale to be closed in the second quarter. In addition, Range currently is marketing its central Oklahoma properties.
Capital Spending Plans and Cost Overview/Outlook
Range has set its 2016 capital spending budget at $495 million, a decrease of 45% compared to 2015 and a decrease of 69% compared to 2014. The capital budget includes approximately $470 million for drilling and recompletions, $20 million for leasehold and renewals and $5 million for seismic, facilities and other. Substantially all the activity is focused in the Marcellus for 2016. Adjusted for the Nora and Bradford County sales, production growth is projected to be 8% to 10% year-over-year despite.
Fourth quarter 2015 drilling expenditures of $83 million funded the drilling of 27 (25 net) wells. Drilling expenditures for the year totaled $796 million, and Range drilled 152 (141 net) wells and 3 recompletions during the year. A 100% success rate was achieved. In addition, during the year, $73 million was spent on acreage purchases, $13 million on gas gathering systems and $18 million on exploration expense. Drill-bit only finding cost averaged $0.37 per mcfe, including pricing and performance revisions with a reserve replacement ratio of 436%.
Total unit costs for fourth quarter 2015 decreased by 15% compared to the prior-year quarter. The improving unit costs were led by a 33% decline in general and administrative expense to $0.22 per mcfe (excluding stock-based compensation), as the Company’s employee count has been reduced by 31% through asset sales and other workforce reductions. Direct operating expense, production taxes and transportation expenses totaled $1.13 per mcfe, a decrease of 4% compared to the prior-year quarter. Interest expense was $0.31 per mcfe, 6% lower than the previous year. In total, cash unit costs decreased 10% to $1.66, while depreciation, depletion and amortization expense decreased 22% to $0.97 per mcfe. All unit costs are expected to improve further in 2016, when compared to 2015 with the exception of transportation, gathering and compression expense. However, the increased expense related to firm transportation for natural gas and NGLs is expected to improve differentials for the Company’s NGL and natural gas production, more than offsetting increased expenses.
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Operational Discussion
Range has updated its investor presentation with updated economic sensitivity analysis for the Marcellus. Please see www.rangeresources.com under the Investors tab, “Company Presentations” area, for the presentation entitled, “Company Presentation – February 26, 2016”
Marcellus Shale
Production for the fourth quarter of 2015 averaged approximately 1,275 net Mmcfe per day for the Marcellus Shale divisions, an 18% increase over the prior year. The Southern Marcellus Shale Division averaged 1,031 net Mmcfe per day during the quarter, a 25% increase over the prior year. The Northern Marcellus Shale Division averaged 244 net Mmcf per day during the quarter, a 6% decrease over the prior year.
Range has updated well economics and type curves for the planned 2016 Marcellus drilling program, which can be found on the Company’s website in the most recent investor presentation. Consistent with the prior year, updated type curves reflect expected flow restrictions that result from infrastructure and facility constraints. The Company manages development of its Marcellus assets in order to maximize project returns. As a result, early production from prolific Marcellus wells is often constrained, resulting in flatter decline curves, and is reflected in the type curves. As seen in the presentation slides, wells turned in line (“TIL”) over the past two years continue to perform in line with type curve expectations. These results demonstrate the quality of acreage as the Company continues development across its core position in southwest Pennsylvania.
The table below summarizes the 2015 activity and estimates for 2016 regarding the number of wells to sales, average lateral lengths, well costs, EURs by area and Range’s current net acreage for the Marcellus only.
| Wells TIL in 2015 |
Average 2015 Lateral Length |
Planned Wells TIL in 2016 |
Expected Average 2016 Lateral Length | |||||
| SW PA Super-Rich |
25 | 5,367 ft. | 13 | 6,660 ft. | ||||
| SW PA Wet |
49 | 5,955 ft. | 38 | 6,970 ft. | ||||
| SW PA Dry |
33 | 6,798 ft. | 38 | 7,000 ft. | ||||
| NE PA Dry |
19 | 5,663 ft. | 14 | 5,660 ft. | ||||
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| Total Marcellus |
126 | 103 |
| Expected 2016 Well Costs |
Projected EURs for 2016 Wells |
Net Acreage by Area (Marcellus only) | ||||
| SW PA Super-Rich |
$5.9 million | 16.0 Bcfe | 110,000 | |||
| SW PA Wet |
$5.8 million | 20.6 Bcfe | 225,000 | |||
| SW PA Dry |
$5.2 million | 17.6 Bcf | 180,000 | |||
| NE PA Dry |
$2.9 million | 14.1 Bcf | 110,000 | |||
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| Total Marcellus |
625,000 | |||||
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In 2015, the Company completed its second successful Utica well beneath its Marcellus position in Washington County, Pennsylvania. The two wells have produced 4.2 Bcf through year-end. In development mode, well costs could potentially be in the $12 to $14 million range for 6,500 to 8,000 foot laterals. While these potential economics are encouraging, the Company will continue to focus its capital on its prolific Marcellus acreage position that has been de-risked by approximately 8,000 industry wells throughout the play. Range expects to bring one additional Utica well to sales in 2016, which was drilled in 2015. Range has approximately 400,000 acres in southwest Pennsylvania which it considers prospective for Utica development.
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Marcellus Shale Marketing and Transportation
The Mariner East project started the commissioning process for ethane in late 2015, commissioned the refrigeration system in January and introduced ethane into the pipeline for the first time in early February. Sunoco Logistics expects to be loading the first ethane ship in a few days. Range has begun shipping 20,000 barrels per day of ethane and 20,000 barrels per day of propane via pipeline to the Marcus Hook terminal facilities in Philadelphia. The ethane will be sold to INEOS, FOB Marcus Hook, under a 15-year sales agreement, and propane will be sold in either the international market or the local market, depending on which yields the best price. The supply of large ships available to transport propane to international markets is expected to increase by roughly 50% in 2016, which is expected to lower shipping costs and improve the expected net price received for propane. Range has begun to hedge the premium spread between the Mont Belvieu propane index and the respective European and Asian propane market indexes for 2016. Due in large part to the Mariner East startup, Range expects its NGL differentials to improve in 2016. This is expected to be most evident in the summer months of 2016, when, much like the summer of 2015, propane supply in the Appalachian market is expected to be much greater than the local demand which requires additional transportation costs to move the propane to a sales market or storage facility. The Company anticipates corporate realized NGL prices to average approximately 23% to 25% of WTI price in 2016 compared to the 17.6% of WTI experienced in 2015. On a gross basis, without processing fees and comparable to other Appalachian peers, Range’s Marcellus C3+ NGL barrel is currently expected to be approximately 45% of WTI in 2016 after Mariner East is fully operational.
Range’s marketing team has also put in place strategic outlets for natural gas that are currently being realized, as demonstrated by improved natural gas differentials during the fourth quarter. Specifically, the Company had a full quarter of utilizing Spectra’s Uniontown to Gas City transportation which moves natural gas from Appalachia to Gas City, Indiana. This transportation arrangement was part of the reason for the Company’s $0.41 improvement in differential from third quarter 2015 to fourth quarter 2015. As Range is able to take advantage of these incremental natural gas transportation projects that began in 2015, the Company expects to see further improvements in Marcellus natural gas differentials in 2016. The Company currently expects Marcellus differentials of approximately $0.40 to $0.45 per mcf under NYMEX for full-year 2016 compared to the 2015 Marcellus differential of $0.62.
During the second half of 2015, Range initiated a new marketing arrangement for condensate sales and improved the Company’s oil differentials from approximately $16 under WTI in the first half of the year to approximately $13.50 under WTI during the second half of 2015. Under the new agreement, Range is upgrading its transportation logistics arrangements which will allow multiple options in marketing condensate production going forward. During the third quarter of 2015, Range became the first Appalachian producer to provide condensate barrels for export to overseas markets. In 2016, consistent with the second half of last year, Range currently expects corporate realized oil and condensate differentials to average approximately $13 to $14 under WTI price.
Guidance – 2016
Production per day Guidance
Production for the entire 2016 year is expected to average 1,390 to 1,420 Mmcfe per day. This equates to an 8% to 10% production growth for the year on a pro forma basis, adjusted for asset sales. Production for the first quarter of 2016 is expected to be approximately 1,350 Mmcfe per day with 30% to 32% liquids.
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1Q 2016 Expense Guidance
| Direct operating expense: |
$0.25 - $0.27 per mcfe | |
| Transportation, gathering and compression expense: |
$1.03 - $1.05 per mcfe | |
| Production tax expense: |
$0.06 - $0.07 per mcfe | |
| Exploration expense: |
$5.0 - $7.0 million | |
| Unproved property impairment expense: |
$11.0 - $13.0 million | |
| G&A expense: |
$0.24 - $0.26 per mcfe | |
| Interest expense: |
$0.30 - $0.31 per mcfe | |
| DD&A expense: |
$0.97 - $0.99 per mcfe |
2016 Differentials
Based on current market pricing indications, Range would expect to receive the following pre-hedge differentials for its production in 2016.
| Natural Gas: |
NYMEX minus $0.40 - $0.45 | |
| Natural Gas Liquids (including ethane): |
23% - 25% of WTI | |
| Oil/Condensate: |
WTI minus $13 - $14 |
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 approximately 80% of its expected 2016 natural gas production hedged at a weighted average floor price of $3.24 per mcf. Similarly, Range has hedged approximately 50% of its 2016 projected crude oil production at a floor price of $65.27 and approximately 50% of its composite 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.
Range has also hedged Marcellus and other basis differentials covering 120,000 Mmbtu per day from January through March 2016, and 130,000 Mmbtu per day for April 2016 through October 2016. The fair value of the basis hedges based upon future strip prices as of December 31, 2015 was a gain of $5.5 million.
Conference Call Information
A conference call to review the financial results is scheduled on Friday, February 26 at 9:00 a.m. ET. To participate in the call, please dial 877-407-0778 and ask for the Range Resources 2015 financial results conference call. A replay of the call will be available through March 26. To access the phone replay dial 877-660-6853. The conference ID is 13628714.
A simultaneous webcast of the call may be accessed at www.rangeresources.com. The webcast will be archived for replay on the Company’s website until March 26.
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 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 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
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reconciles income or loss from operations to adjusted net income comparable to analysts’ estimates and diluted earnings per share (adjusted). On its website, the Company provides additional comparative information on prior periods along with non-GAAP revenue disclosures.
Cash flow from operations before changes in working capital (sometimes referred to as “adjusted cash flow”) as defined in this release represents net cash provided by operations before changes in working capital and exploration expense adjusted for certain non-cash compensation items. Cash flow from operations before changes in working capital is widely accepted by the investment community as a financial indicator of an oil and gas company’s ability to generate cash to internally fund exploration and development activities and to service debt. Cash flow from operations before changes in working capital is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Cash flow from operations before changes in working capital is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operations, investing, or financing activities as an indicator of cash flows, or as a measure of liquidity. A table is included which reconciles Net cash provided by operations to Cash flow from operations before changes in working capital as used in this release. On its website, the Company provides additional comparative information on prior periods for cash flow, cash margins and non-GAAP earnings as used in this release.
The cash prices realized for oil and natural gas production including the amounts realized on cash-settled derivatives and net of transportation, gathering and compression expense is a critical component in the Company’s performance tracked by investors and professional research analysts in valuing, comparing, rating and providing investment recommendations and forecasts of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Due to the GAAP disclosures of various derivative transactions and third-party transportation, gathering and compression expense, such information is now reported in various lines of the income statement. The Company believes that it is important to furnish a table reflecting the details of the various components of each income statement line to better inform the reader of the details of each amount and provide a summary of the realized cash-settled amounts and third-party transportation, gathering and compression expense which historically were reported as natural gas, NGLs and oil sales. This information is intended 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 GAAP financial statements included in the Company’s Annual Report on Form 10-K. 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.
Range has disclosed two primary metrics in this release to measure our ability to establish a long-term trend of adding reserves at a reasonable cost – a reserve replacement ratio and finding and development cost per unit. The reserve replacement ratio is an indicator of our ability to replace annual production volumes and grow our reserves. It is important to economically find and develop new reserves that will offset produced volumes and provide for future production given the inherent decline of hydrocarbon reserves as they are produced. We believe the ability to develop a competitive advantage over other natural gas and oil companies is dependent on adding reserves in our core areas at lower costs than our competition. The reserve replacement ratio is calculated by dividing production for the year into the total of proved reserve extensions, discoveries and additions and proved reserves revisions, excluding PUD removals based on the SEC 5-year rule.
Finding and development cost per unit is a non-GAAP metric used in the exploration and production industry by companies, investors and analysts. The calculations presented by the Company are based on estimated and unaudited costs incurred excluding asset retirement obligations and divided by proved reserve additions (extensions, discoveries and additions) adjusted for the changes in proved reserves for acquisitions, performance revisions and/or price revisions and including or excluding acreage costs as stated in each instance in the release. Drill-bit development cost per mcfe is based on estimated and unaudited drilling, development and exploration costs incurred divided by the total of reserve additions, performance and price revisions. These calculations do not include the future development costs required for the development of proved undeveloped reserves. The SEC method of computing finding costs contains additional cost components and results in a higher number. A reconciliation of the two methods is shown on our website at www.rangeresources.com.
The reserve replacement ratio and finding and development cost per unit are statistical indicators that have limitations, including their predictive and comparative value. As an annual measure, the reserve
8
replacement ratio can be limited because it may vary widely based on the extent and timing of new discoveries and the varying effects of changes in prices and well performance. In addition, since the reserve replacement ratio and finding and development cost per unit do not consider the cost or timing of future production of new reserves, such measures may not be an adequate measure of value creation. These reserves metrics may not be comparable to similarly titled measurements used by other companies.
RANGE RESOURCES CORPORATION (NYSE: RRC) is a leading independent oil and natural gas producer with operations focused in stacked-pay projects in the Appalachia Basin. 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 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, expected future sales of assets, 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, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. 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
9
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.
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.
2016-03
SOURCE: Range Resources Corporation
Investor Contacts:
Rodney Waller, Senior Vice President
817-869-4258
rwaller@rangeresources.com
Laith Sando, Vice President – Investor Relations
817-869-4267
lsando@rangeresources.com
David Amend, Investor Relations Manager
817-869-4266
damend@rangeresources.com
Michael Freeman, Senior Financial Analyst
817-869-4264
mfreeman@rangeresources.com
Media Contact:
Matt Pitzarella, Director of Corporate Communications
724-873-3224
mpitzarella@rangeresources.com
www.rangeresources.com
10
RANGE RESOURCES CORPORATION
STATEMENTS OF OPERATIONS
Based on GAAP reported earnings with additional details of items included in each line in Form 10-K (Unaudited, in thousands, except per share data)
| Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||||||||||
| 2015 | 2014 | % | 2015 | 2014 | % | |||||||||||||||||||
| Revenues and other income: |
||||||||||||||||||||||||
| Natural gas, NGLs and oil sales (a) |
$ | 254,043 | $ | 416,388 | $ | 1,089,644 | $ | 1,911,989 | ||||||||||||||||
| Derivative fair value (loss)/income |
126,312 | 412,422 | 416,364 | 383,520 | ||||||||||||||||||||
| Brokered natural gas, marketing and other (b) |
30,100 | 31,424 | 90,922 | 123,065 | ||||||||||||||||||||
| Equity method investment (b) |
— | — | — | (277 | ) | |||||||||||||||||||
| ARO settlement (b) |
80 | 8,196 | 103 | 7,545 | ||||||||||||||||||||
| Other (b) |
192 | 24 | 1,035 | 215 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total revenues and other income |
410,727 | 868,454 | -53 | % | 1,598,068 | 2,426,057 | -34 | % | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Costs and expenses: |
||||||||||||||||||||||||
| Direct operating |
28,757 | 37,262 | 133,583 | 146,275 | ||||||||||||||||||||
| Direct operating – non-cash stock-based compensation (c) |
631 | 699 | 2,780 | 4,208 | ||||||||||||||||||||
| Transportation, gathering and compression |
112,481 | 89,542 | 396,739 | 325,289 | ||||||||||||||||||||
| Production and ad valorem taxes |
7,354 | 11,923 | 33,860 | 44,555 | ||||||||||||||||||||
| Brokered natural gas and marketing |
34,553 | 31,161 | 113,734 | 126,457 | ||||||||||||||||||||
| Brokered natural gas and marketing – non-cash stock-based compensation (c) |
389 | 1,209 | 2,132 | 3,523 | ||||||||||||||||||||
| Exploration |
3,446 | 22,477 | 18,421 | 58,979 | ||||||||||||||||||||
| Exploration – non-cash stock-based compensation (c) |
814 | 1,161 | 2,985 | 4,569 | ||||||||||||||||||||
| Abandonment and impairment of unproved properties |
11,432 | 14,308 | 47,619 | 47,079 | ||||||||||||||||||||
| General and administrative |
29,476 | 39,034 | 136,290 | 148,888 | ||||||||||||||||||||
| General and administrative – non-cash stock-based compensation (c) |
11,142 | 11,526 | 49,687 | 55,382 | ||||||||||||||||||||
| General and administrative – lawsuit settlements |
1,226 | 804 | 3,238 | 3,007 | ||||||||||||||||||||
| General and administrative – bad debt expense |
1,700 | — | 2,300 | 250 | ||||||||||||||||||||
| General and administrative – legal contingency (DEP penalty in prior year) |
— | 999 | 2,500 | 5,899 | ||||||||||||||||||||
| Termination costs |
10,283 | 5,372 | 14,853 | 5,372 | ||||||||||||||||||||
| Termination costs – non-cash stock-based compensation (c) |
(1,503 | ) | 2,999 | 217 | 2,999 | |||||||||||||||||||
| Deferred compensation plan (d) |
(21,016 | ) | (36,836 | ) | (77,627 | ) | (74,550 | ) | ||||||||||||||||
| Interest expense |
40,849 | 38,900 | 166,439 | 168,977 | ||||||||||||||||||||
| Loss on early extinguishment of debt |
— | — | 22,495 | 24,596 | ||||||||||||||||||||
| Depletion, depreciation and amortization |
127,977 | 146,539 | 581,155 | 551,032 | ||||||||||||||||||||
| Impairment of proved properties and other assets |
87,941 | 3,033 | 590,174 | 28,024 | ||||||||||||||||||||
| Loss (gain) on sale of assets |
408,909 | (3,760 | ) | 406,856 | (285,638 | ) | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total costs and expenses |
896,841 | 418,352 | 114 | % | 2,650,430 | 1,395,172 | 90 | % | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| (Loss) income before income taxes |
(486,114 | ) | 450,102 | -208 | % | (1,052,362 | ) | 1,030,885 | -202 | % | ||||||||||||||
| Income tax (benefit) expense: |
||||||||||||||||||||||||
| Current |
29 | (4 | ) | 29 | 1 | |||||||||||||||||||
| Deferred |
(164,316 | ) | 166,052 | (338,706 | ) | 396,502 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| (164,287 | ) | 166,048 | (338,677 | ) | 396,503 | |||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Net (loss) income |
$ | (321,827 | ) | $ | 284,054 | -213 | % | $ | (713,685 | ) | $ | 634,382 | -213 | % | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Net (Loss) Income Per Common Share: |
||||||||||||||||||||||||
| Basic |
$ | (1.93 | ) | $ | 1.68 | $ | (4.29 | ) | $ | 3.81 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Diluted |
$ | (1.93 | ) | $ | 1.68 | $ | (4.29 | ) | $ | 3.79 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Weighted average common shares outstanding, as reported: |
||||||||||||||||||||||||
| Basic |
166,573 | 165,877 | 0 | % | 166,389 | 163,625 | 2 | % | ||||||||||||||||
| Diluted |
166,573 | 166,164 | 0 | % | 166,389 | 164,403 | 1 | % | ||||||||||||||||
| (a) | See separate natural gas, NGLs and oil sales information table. |
| (b) | Included in Brokered natural gas, marketing and other revenues in the 10-K. |
| (c) | 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-K. |
| (d) | Reflects the change in market value of the vested Company stock held in the deferred compensation plan. |
11
RANGE RESOURCES CORPORATION
BALANCE SHEETS
| (In thousands) | December 31, | December 31, | ||||||
| 2015 | 2014 | |||||||
| (Audited) | (Audited) | |||||||
| Assets |
||||||||
| Current assets |
$ | 157,530 | $ | 207,243 | ||||
| Derivative assets |
288,762 | 403,363 | ||||||
| Natural gas and oil properties, successful efforts method |
6,361,305 | 7,977,573 | ||||||
| Transportation and field assets |
19,455 | 37,581 | ||||||
| Other |
72,979 | 78,844 | ||||||
|
|
|
|
|
|||||
| $ | 6,900,031 | $ | 8,704,604 | |||||
|
|
|
|
|
|||||
| Liabilities and Stockholders’ Equity |
||||||||
| Current liabilities |
$ | 335,513 | $ | 624,610 | ||||
| Asset retirement obligations |
15,071 | 15,067 | ||||||
| Derivative liabilities |
1,136 | — | ||||||
| Bank debt |
86,427 | 713,221 | ||||||
| Senior notes |
738,101 | — | ||||||
| Senior subordinated notes |
1,826,775 | 2,317,603 | ||||||
|
|
|
|
|
|||||
| 2,651,303 | 3,030,824 | |||||||
|
|
|
|
|
|||||
| Deferred tax liability |
777,947 | 1,113,081 | ||||||
| Derivative liabilities |
21 | — | ||||||
| Deferred compensation liability |
104,792 | 178,599 | ||||||
| Asset retirement obligations and other liabilities |
254,590 | 284,994 | ||||||
|
|
|
|
|
|||||
| 1,137,350 | 1,576,674 | |||||||
| Common stock and retained earnings |
2,761,903 | 3,460,517 | ||||||
| Common stock held in treasury stock |
(2,245 | ) | (3,088 | ) | ||||
|
|
|
|
|
|||||
| Total stockholders’ equity |
2,759,658 | 3,457,429 | ||||||
|
|
|
|
|
|||||
| $ | 6,900,031 | $ | 8,704,604 | |||||
|
|
|
|
|
|||||
RECONCILIATION OF TOTAL REVENUES AND OTHER INCOME TO TOTAL REVENUE EXCLUDING CERTAIN ITEMS, a non-GAAP measure
| (Unaudited, in thousands) | Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||||||||||
| 2015 | 2014 | % | 2015 | 2014 | % | |||||||||||||||||||
| Total revenues and other income, as reported |
$ | 410,727 | $ | 868,454 | -53 | % | $ | 1,598,068 | $ | 2,426,057 | -34 | % | ||||||||||||
| Adjustment for certain special items: |
||||||||||||||||||||||||
| Total change in fair value related to derivatives prior to settlement (gain) loss |
45,165 | (341,197 | ) | 115,758 | (426,154 | ) | ||||||||||||||||||
| ARO settlement (gain) loss |
(80 | ) | (8,196 | ) | (103 | ) | (7,545 | ) | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total revenues, as adjusted, non-GAAP |
$ | 455,812 | $ | 519,061 | -12 | % | $ | 1,713,723 | $ | 1,992,358 | -14 | % | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
12
RANGE RESOURCES CORPORATION
| CASH FLOWS FROM OPERATING ACTIVITIES
|
||||||||||||||||
| (Unaudited, in thousands) | Three Months Ended December 31, |
Twelve Months Ended December 31, |
||||||||||||||
| 2015 | 2014 | 2015 | 2014 | |||||||||||||
| Net (loss) income |
$ | (321,827 | ) | $ | 284,054 | $ | (713,685 | ) | $ | 634,382 | ||||||
| Adjustments to reconcile net cash provided from continuing operations: |
||||||||||||||||
| (Gain) loss from equity method investment, net of distributions |
— | (1 | ) | — | 3,095 | |||||||||||
| Deferred income tax (benefit) expense |
(164,316 | ) | 166,052 | (338,706 | ) | 396,502 | ||||||||||
| Depletion, depreciation, amortization and impairment |
215,918 | 149,572 | 1,171,329 | 579,056 | ||||||||||||
| Exploration dry hole costs |
1 | 16,144 | 88 | 16,145 | ||||||||||||
| Abandonment and impairment of unproved properties |
11,432 | 14,308 | 47,619 | 47,079 | ||||||||||||
| Derivative fair value (income) loss |
(126,312 | ) | (412,422 | ) | (416,364 | ) | (383,520 | ) | ||||||||
| Cash settlements on derivative financial instruments that do not qualify for hedge accounting |
171,477 | 71,225 | 532,122 | (42,634 | ) | |||||||||||
| Allowance for bad debts |
1,700 | — | 2,300 | 250 | ||||||||||||
| Amortization of deferred issuance costs, loss on extinguishment of debt, and other |
1,811 | (6,736 | ) | 29,383 | 24,694 | |||||||||||
| Deferred and stock-based compensation |
(9,732 | ) | (19,781 | ) | (20,411 | ) | (4,295 | ) | ||||||||
| (Gain) loss on sale of assets and other |
408,909 | (3,760 | ) | 406,856 | (285,638 | ) | ||||||||||
| Changes in working capital: |
||||||||||||||||
| Accounts receivable |
(14,744 | ) | (18,427 | ) | 64,704 | (5,329 | ) | |||||||||
| Inventory and other |
(7,795 | ) | 814 | (14,868 | ) | (4,521 | ) | |||||||||
| Accounts payable |
(13,039 | ) | 12,332 | (26,197 | ) | (1,023 | ) | |||||||||
| Accrued liabilities and other |
14,657 | 45,823 | (40,470 | ) | (20,108 | ) | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net changes in working capital |
(20,921 | ) | 40,542 | (16,831 | ) | (30,981 | ) | |||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net cash provided from operating activities |
$ | 168,140 | $ | 299,197 | $ | 683,700 | $ | 954,135 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
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 December 31, |
Twelve Months Ended December 31, |
||||||||||||||
| 2015 | 2014 | 2015 | 2014 | |||||||||||||
| Net cash provided from operating activities, as reported |
$ | 168,140 | $ | 299,197 | $ | 683,700 | $ | 954,135 | ||||||||
| Net changes in working capital |
20,921 | (40,542 | ) | 16,831 | 30,981 | |||||||||||
| Exploration expense |
3,445 | 6,333 | 18,333 | 42,834 | ||||||||||||
| Lawsuit settlements |
1,226 | 804 | 3,238 | 3,007 | ||||||||||||
| Legal contingency/DEP penalty |
— | 999 | 2,500 | 5,899 | ||||||||||||
| Equity method investment distribution / intercompany elimination |
— | — | — | (2,819 | ) | |||||||||||
| Termination costs |
10,140 | 5,372 | 14,710 | 5,372 | ||||||||||||
| Non-cash compensation adjustment |
216 | 661 | 852 | 907 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Cash flow from operations before changes in working capital – a non-GAAP measure |
$ | 204,088 | $ | 272,824 | $ | 740,164 | $ | 1,040,316 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING
| (Unaudited, in thousands) | Three Months Ended December 31, |
Twelve Months Ended December 31, |
||||||||||||||
| 2015 | 2014 | 2015 | 2014 | |||||||||||||
| Basic: |
||||||||||||||||
| Weighted average shares outstanding |
169,371 | 168,705 | 169,183 | 166,439 | ||||||||||||
| Stock held by deferred compensation plan |
(2,798 | ) | (2,828 | ) | (2,794 | ) | (2,814 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Adjusted basic |
166,573 | 165,877 | 166,389 | 163,625 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Dilutive: |
||||||||||||||||
| Weighted average shares outstanding |
169,371 | 168,705 | 169,183 | 166,439 | ||||||||||||
| Dilutive stock options under treasury method |
(2,798 | ) | (2,541 | ) | (2,794 | ) | (2,036 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Adjusted dilutive |
166,573 | 166,164 | 166,389 | 164,403 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
13
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, a non-GAAP measure
| (Unaudited, in thousands, except per unit data) | Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||||||||||
| 2015 | 2014 | % | 2015 | 2014 | % | |||||||||||||||||||
| Natural gas, NGL and oil sales components: |
||||||||||||||||||||||||
| Natural gas sales |
$ | 183,576 | $ | 266,475 | $ | 773,093 | $ | 1,140,989 | ||||||||||||||||
| NGL sales |
44,724 | 88,792 | 176,546 | 444,152 | ||||||||||||||||||||
| Oil sales |
25,743 | 61,479 | 140,005 | 316,625 | ||||||||||||||||||||
| Cash-settled hedges (effective): |
||||||||||||||||||||||||
| Natural gas |
— | (2,074 | ) | — | 4,686 | |||||||||||||||||||
| Crude oil |
— | 1,716 | — | 5,537 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total oil and gas sales, as reported |
$ | 254,043 | $ | 416,388 | -39 | % | $ | 1,089,644 | $ | 1,911,989 | -43 | % | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Derivative fair value income (loss), as reported: |
$ | 126,312 | $ | 412,422 | $ | 416,364 | $ | 383,520 | ||||||||||||||||
| Cash settlements on derivative financial instruments – (gain) loss: |
||||||||||||||||||||||||
| Natural gas |
(115,428 | ) | (25,541 | ) | (339,031 | ) | 58,442 | |||||||||||||||||
| NGLs |
(10,366 | ) | (26,551 | ) | (41,974 | ) | (13,437 | ) | ||||||||||||||||
| Crude Oil |
(45,683 | ) | (19,133 | ) | (151,117 | ) | (2,371 | ) | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total change in fair value related to derivatives prior to settlement, a non-GAAP measure |
$ | (45,165 | ) | $ | 341,197 | $ | (115,758 | ) | $ | 426,154 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Transportation, gathering and compression components: |
||||||||||||||||||||||||
| Natural gas |
$ | 95,849 | $ | 76,682 | $ | 343,593 | $ | 282,447 | ||||||||||||||||
| NGLs |
16,632 | 12,860 | 53,146 | 42,842 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total transportation, gathering and compression, as reported |
$ | 112,481 | $ | 89,542 | $ | 396,739 | $ | 325,289 | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Natural gas, NGL and oil sales, including cash-settled derivatives: (c) |
||||||||||||||||||||||||
| Natural gas sales |
$ | 299,004 | $ | 289,942 | $ | 1,112,124 | $ | 1,087,233 | ||||||||||||||||
| NGL sales |
55,090 | 115,343 | 218,520 | 457,589 | ||||||||||||||||||||
| Oil sales |
71,426 | 82,328 | 291,122 | 324,533 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total |
$ | 425,520 | $ | 487,613 | -13 | % | $ | 1,621,766 | $ | 1,869,355 | -13 | % | ||||||||||||
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|
|
|
|
|
|
|
|
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| Production of oil and gas during the periods (a): |
||||||||||||||||||||||||
| Natural gas (mcf) |
97,175,602 | 81,481,720 | 19 | % | 362,686,707 | 286,926,099 | 26 | % | ||||||||||||||||
| NGL (bbl) |
4,906,615 | 4,943,309 | -1 | % | 20,356,110 | 18,820,526 | 8 | % | ||||||||||||||||
| Oil (bbl) |
897,064 | 1,059,514 | -15 | % | 4,084,069 | 4,069,568 | 0 | % | ||||||||||||||||
| Gas equivalent (mcfe) (b) |
131,997,676 | 117,498,658 | 12 | % | 509,327,781 | 424,266,663 | 20 | % | ||||||||||||||||
| Production of oil and gas – average per day (a): |
||||||||||||||||||||||||
| Natural gas (mcf) |
1,056,257 | 885,671 | 19 | % | 993,662 | 786,099 | 26 | % | ||||||||||||||||
| NGL (bbl) |
53,333 | 53,732 | -1 | % | 55,770 | 51,563 | 8 | % | ||||||||||||||||
| Oil (bbl) |
9,751 | 11,516 | -15 | % | 11,189 | 11,150 | 0 | % | ||||||||||||||||
| Gas equivalent (mcfe) (b) |
1,434,757 | 1,277,159 | 12 | % | 1,395,419 | 1,162,374 | 20 | % | ||||||||||||||||
| Average prices, including cash-settled hedges that qualify for hedge accounting before third party transportation costs: |
||||||||||||||||||||||||
| Natural gas (mcf) |
$ | 1.89 | $ | 3.24 | -42 | % | $ | 2.13 | $ | 3.99 | -47 | % | ||||||||||||
| NGL (bbl) |
$ | 9.12 | $ | 17.96 | -49 | % | $ | 8.67 | $ | 23.60 | -63 | % | ||||||||||||
| Oil (bbl) |
$ | 28.70 | $ | 59.65 | -52 | % | $ | 34.28 | $ | 79.16 | -57 | % | ||||||||||||
| Gas equivalent (mcfe) (b) |
$ | 1.92 | $ | 3.54 | -46 | % | $ | 2.14 | $ | 4.51 | -53 | % | ||||||||||||
| Average prices, including cash-settled hedges and derivatives before third party transportation costs: (c) |
||||||||||||||||||||||||
| Natural gas (mcf) |
$ | 3.08 | $ | 3.56 | -14 | % | $ | 3.07 | $ | 3.79 | -19 | % | ||||||||||||
| NGL (bbl) |
$ | 11.23 | $ | 23.33 | -52 | % | $ | 10.73 | $ | 24.31 | -56 | % | ||||||||||||
| Oil (bbl) |
$ | 79.62 | $ | 77.70 | 2 | % | $ | 71.28 | $ | 79.75 | -11 | % | ||||||||||||
| Gas equivalent (mcfe) (b) |
$ | 3.22 | $ | 4.15 | -22 | % | $ | 3.18 | $ | 4.41 | -28 | % | ||||||||||||
| Average prices, including cash-settled hedges and derivatives: (d) |
||||||||||||||||||||||||
| Natural gas (mcf) |
$ | 2.09 | $ | 2.62 | -20 | % | $ | 2.12 | $ | 2.80 | -24 | % | ||||||||||||
| NGL (bbl) |
$ | 7.84 | $ | 20.73 | -62 | % | $ | 8.12 | $ | 22.04 | -63 | % | ||||||||||||
| Oil (bbl) |
$ | 79.62 | $ | 77.70 | 2 | % | $ | 71.28 | $ | 79.75 | -11 | % | ||||||||||||
| Gas equivalent (mcfe) (b) |
$ | 2.37 | $ | 3.39 | -30 | % | $ | 2.41 | $ | 3.64 | -34 | % | ||||||||||||
| Transportation, gathering and compression expense per mcfe |
$ | 0.85 | $ | 0.76 | 12 | % | $ | 0.78 | $ | 0.77 | 2 | % | ||||||||||||
| (a) | Represents volumes sold regardless of when produced. |
| (b) | Oil and NGLs are converted at the rate of one barrel equals six mcfe based upon the approximate relative energy content of oil to natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices. |
| (c) | Excluding third party transportation, gathering and compression costs. |
| (d) | Net of transportation, gathering and compression costs. |
14
RANGE RESOURCES CORPORATION
RECONCILIATION OF (LOSS) 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 December 31, | Twelve Months Ended December 31, | ||||||||||||||||||||||
| 2015 | 2014 | % | 2015 | 2014 | % | |||||||||||||||||||
| (Loss) income from operations before income taxes, as reported |
$ | (486,114 | ) | $ | 450,102 | -208 | % | $ | (1,052,362 | ) | $ | 1,030,885 | -202 | % | ||||||||||
| Adjustment for certain special items: |
||||||||||||||||||||||||
| Loss (gain) on sale of assets |
408,909 | (3,760 | ) | 406,856 | (285,638 | ) | ||||||||||||||||||
| (Gain) loss on ARO settlements |
(80 | ) | (8,196 | ) | (103 | ) | (7,545 | ) | ||||||||||||||||
| Change in fair value related to derivatives prior to settlement |
45,165 | (341,197 | ) | 115,758 | (426,154 | ) | ||||||||||||||||||
| Abandonment and impairment of unproved properties |
11,432 | 14,308 | 47,619 | 47,079 | ||||||||||||||||||||
| Loss on early extinguishment of debt |
— | — | 22,495 | 24,596 | ||||||||||||||||||||
| Impairment of proved property and other assets |
87,941 | 3,033 | 590,174 | 28,024 | ||||||||||||||||||||
| Lawsuit settlements |
1,226 | 804 | 3,238 | 3,007 | ||||||||||||||||||||
| DEP penalty |
— | 999 | — | 5,899 | ||||||||||||||||||||
| Legal contingency |
— | — | 2,500 | — | ||||||||||||||||||||
| Termination costs |
10,283 | 5,372 | 14,853 | 5,372 | ||||||||||||||||||||
| Termination costs – non-cash stock-based compensation |
(1,503 | ) | 2,999 | 217 | 2,999 | |||||||||||||||||||
| Brokered natural gas and marketing – non-cash stock-based compensation |
389 | 1,209 | 2,132 | 3,523 | ||||||||||||||||||||
| Direct operating – non-cash stock-based compensation |
631 | 699 | 2,780 | 4,208 | ||||||||||||||||||||
| Exploration expenses – non-cash stock-based compensation |
814 | 1,161 | 2,985 | 4,569 | ||||||||||||||||||||
|
General & administrative – non-cash stock-based compensation |
11,142 | 11,526 | 49,687 | 55,382 | ||||||||||||||||||||
| Deferred compensation plan – non-cash adjustment |
(21,016 | ) | (36,836 | ) | (77,627 | ) | (74,550 | ) | ||||||||||||||||
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| Income from operations before income taxes, as adjusted |
69,219 | 102,223 | -32 | % | 131,202 | 421,656 | -69 | % | ||||||||||||||||
| Income tax expense, as adjusted |
||||||||||||||||||||||||
| Current |
29 | (4 | ) | 29 | 1 | |||||||||||||||||||
| Deferred |
27,431 | 37,680 | 50,777 | 161,460 | ||||||||||||||||||||
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| Net income excluding certain items, a non-GAAP measure |
$ | 41,759 | $ | 64,547 | -35 | % | $ | 80,396 | $ | 260,195 | -69 | % | ||||||||||||
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| Non-GAAP income per common share |
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| Basic |
$ | 0.25 | $ | 0.39 | -36 | % | $ | 0.48 | $ | 1.59 | -70 | % | ||||||||||||
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| Diluted |
$ | 0.25 | $ | 0.39 | -36 | % | $ | 0.48 | $ | 1.58 | -70 | % | ||||||||||||
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| Non-GAAP diluted shares outstanding, if dilutive |
166,881 | 166,164 | 166,432 | 164,403 | ||||||||||||||||||||
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15
RANGE RESOURCES CORPORATION
HEDGING POSITION AS OF FEBRUARY 25, 2016 –
(Unaudited)
| Daily Volume | Hedge Price | |||||||
| Gas (Mmbtu) |
||||||||
| 2016 Swaps |
745,874 | $ | 3.24 | |||||
| 2017 Swaps |
20,000 | $ | 3.49 | |||||
| Oil (Bbls) |
||||||||
| 2016 Swaps |
4,247 | $ | 65.27 | |||||
| 2017 Swaps |
500 | $ | 55.00 | |||||
| C3 Propane (Bbls) |
||||||||
| 2016 Swaps |
5,500 | $ | 0.60 | |||||
| C4 Normal Butane (Bbls) |
||||||||
| 2016 Swaps |
2,688 | $ | 0.71 | |||||
| C5 Natural Gasoline (Bbls) |
||||||||
| 2016 Swaps |
2,749 | $ | 1.20 | |||||
NOTE: SEE WEBSITE FOR OTHER SUPPLEMENTAL INFORMATION FOR THE PERIODS
16