Range Reports 2016 Earnings, Announces 2017 Capital Plans
Highlights –
- Record average daily production of 1.854 Bcfe during the fourth quarter
- 2017 capital budget set at
$1.15 billion , projected to provide 33-35% year-over-year growth in 2017 and approximately 20% organic growth in 2018 North Louisiana well costs reduced to$7.7 million per well from$8.7 million previously- Fourth quarter 2016 unhedged cash margins improved by over four times to
$0.97 per mcfe, compared to$0.22 per mcfe in fourth quarter 2015 - Reserve replacement of 292% at
$0.34 per mcfe drill-bit development cost for 2016
Commenting,
Capital Spending Plans
Range has set its 2017 capital spending budget at
The 2017 capital budget includes approximately
Fourth quarter 2016 drilling expenditures of
Financial Discussion
Except for generally accepted accounting principles (“GAAP”) reported amounts, specific expense categories exclude non-cash impairments, unrealized mark-to-market adjustment 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, processing 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.
Fourth Quarter 2016
GAAP revenues for the fourth quarter of 2016 totaled
Non-GAAP revenues for fourth quarter 2016 totaled
Expenses | 4Q 2016 (per mcfe) |
4Q 2015 (per mcfe) |
Increase (Decrease) |
||||||||
Direct operating | $ | 0.17 | $ | 0.22 | (23 | %) | |||||
Transportation, gathering, processing and compression |
0.96 | 0.85 | 13 | % | |||||||
Production and ad valorem taxes | 0.04 | 0.06 | (33 | %) | |||||||
General and administrative | 0.26 | 0.22 | 18 | % | |||||||
Interest expense | 0.27 | 0.31 | (13 | %) | |||||||
Total cash unit costs | 1.70 | 1.66 | 2 | % | |||||||
Depletion, depreciation and amortization |
0.88 | 0.97 | (9 | %) | |||||||
Total unit costs | $ | 2.58 | $ | 2.63 | (2 | %) | |||||
Fourth quarter 2016 natural gas, NGLs and oil price realizations (including the impact of cash-settled hedges and derivative settlements which correspond to analysts’ estimates) averaged
- Production and realized prices by each commodity for fourth quarter 2016 were: natural gas – 1,244 Mmcf per day (
$2.93 per mcf), NGLs – 89,628 barrels per day ($17.20 per barrel) and crude oil and condensate – 12,005 barrels per day ($61.30 per barrel).
- The average Company natural gas price differential including the impact of basis hedges for the fourth quarter was
($0.37) per mcf, which is unchanged from the prior year. The fourth quarter average natural gas price, before all hedging settlements, increased to$2.62 per mcf as compared to$1.90 per mcf in the prior year. NYMEX natural gas financial hedges increased realizations$0.31 per mcf in the fourth quarter of 2016.
- Pre-hedge NGL realizations improved to 29% of West Texas Intermediate (“WTI”) in fourth quarter 2016, compared to 22% of WTI in the previous year. Total NGL pricing per barrel including ethane and processing expenses after realized cash-settled hedging improved to
$17.20 for the fourth quarter compared to$11.23 per barrel in the prior year. Hedging increased NGL prices by$2.70 per barrel in the fourth quarter compared to$2.12 per barrel in the prior year.
- Crude oil and condensate price realizations, before realized hedges, for the fourth quarter averaged
$44.61 per barrel, or$4.66 below WTI, compared to$13.52 below WTI in the prior year. Hedging added$16 .69 per barrel compared to hedge gains of$50.92 in the prior year.
Full Year 2016
GAAP revenues for 2016 totaled
Non-GAAP revenues for 2016 totaled
Expenses | Full Year 2016 (per mcfe) |
Full Year 2015 (per mcfe) |
Increase (Decrease) |
|||||||
Direct operating | $ | 0.17 | $ | 0.26 | (35 | %) | ||||
Transportation, gathering, processing and compression |
1.00 | 0.78 | 28 | % | ||||||
Production and ad valorem taxes | 0.05 | 0.07 | (29 | %) | ||||||
General and administrative | 0.23 | 0.27 | (15 | %) | ||||||
Interest expense | 0.30 | 0.33 | (9 | %) | ||||||
Total cash unit costs | 1.75 | 1.71 | 2 | % | ||||||
Depletion, depreciation and amortization |
0.93 | 1.14 | (18 | %) | ||||||
Total unit costs | $ | 2.68 | $ | 2.85 | (6 | %) | ||||
The Company announced its full year 2016 natural gas, NGLs and oil price realizations (including the impact of cash-settled hedges and derivative settlements which correspond to analysts’ estimates), which averaged
- Production and realized prices by each commodity for 2016 were: natural gas – 1,027 Mmcf per day (
$2.68 per mcf), NGLs – 76,026 barrels per day ($13.16 per barrel) and crude oil and condensate – 9,861 barrels per day ($47.82 per barrel).
- The 2016 average Company natural gas price differential including the impact of basis hedging improved to
($0.45) per mcf compared to($0.52) per mcf in the prior year. The 2016 average natural gas price, before all hedging settlements, decreased to$2.06 per mcf as compared to$2.13 per mcf in the prior year. NYMEX natural gas financial hedges increased realizations$0.61 per mcf for 2016.
- Pre-hedge NGL realizations improved to 26% of WTI in 2016, compared to 18% of WTI in 2015. Total NGL pricing per barrel including ethane and processing expenses after realized cash-settled hedging was
$13.15 per barrel compared to$10.73 in the prior year. Hedging increased NGL prices by$1.71 per barrel in 2016 compared to$2.06 in the prior year.
- Crude oil and condensate price realizations, before hedges, for the year averaged
$34.60 per barrel, or$9.09 below WTI, compared to$14.93 below WTI in the prior year. Hedging added$13.22 per barrel in 2016, compared to hedge gains of$37.00 per barrel in the prior year.
Operational Discussion
Range has updated its investor presentation with new economic calculations and type curves for the Marcellus and
The table below summarizes the 2016 activity and estimates for 2017 regarding the number of wells to sales, average lateral lengths, well costs, EURs by area and Range’s current net acreage for each area. Consistent with the prior year, updated type curves reflect expected flow restrictions that result from infrastructure and facility design constraints. As a result, early production from prolific wells is often constrained, resulting in flatter decline curves, and is reflected in the type curves. As seen in the presentation slides, Marcellus wells turned in line (“TIL”) over the past three 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. Similar data is expected to be provided for
Wells TIL in 2016 |
Average 2016 Lateral Length |
Planned Wells TIL in 2017 |
Expected Average 2017 Lateral Length |
|||||
SW PA Super-Rich | 14 | 5,100 ft. | 35 | 8,500 ft. | ||||
SW PA Wet | 30 | 6,400 ft. | 56 | 8,300 ft. | ||||
SW PA Dry | 46 | 6,900 ft. | 25 | 8,850 ft. | ||||
NE PA Dry | 19 | 5,700 ft. | 2 | 6,400 ft. | ||||
Total Marcellus | 109 | 118 | ||||||
Upper Red | — | 34 | 7,500 ft. | |||||
Lower Red | — | 13 | 7,500 ft. | |||||
Pink | — | 6 | ||||||
Expansion area | 3 | 3 | ||||||
Total N. LA | 3 | 56 | ||||||
Total | 112 | 174 | ||||||
|
||||||||
Expected 2017 Well Costs |
Projected EURs for 2017 Wells |
Net Acreage by Area (Marcellus only) |
||||||
SW PA Super-Rich | $7.3 million | 20.4 Bcfe | 110,000 | |||||
SW PA Wet | $6.8 million | 24.6 Bcfe | 225,000 | |||||
SW PA Dry | $6.1 million | 22.3 Bcf | 180,000 | |||||
NE PA Dry | $5.0 million | 16.0 Bcf | 95,000 | |||||
Total Marcellus | 610,000 | |||||||
Upper Red | $7.7 million | 17.5 Bcfe | ||||||
Lower Red | $7.7 million | 11.8 Bcfe | ||||||
Total N. LA | 220,000 | |||||||
Total | 830,000 | |||||||
Production for the fourth quarter of 2016 averaged approximately 1,419 net Mmcfe per day for both
The team continues to look for ways to reduce costs and increase recoveries. Several recent examples are shown below, which have continued to drive lower normalized well costs and reductions in operating costs per mcfe.
- Lateral lengths averaged 6,500 feet in 2016, compared to 6,100 feet in 2015, with projected lateral lengths in 2017 expected to average over 8,000 feet
- Reduced water handling costs in 2016 by over
$30 million compared to 2015 - Increased lateral feet drilled per day by 40% compared to the previous year
- Reduced average completion costs per lateral foot by 14% compared to the previous year
- Managed service costs through better utilization rates and long-term vendor relationships
A recent example of what we expect when going back to core areas with longer laterals is a four well pad in the wet area brought on line in the fourth quarter, with an average 9,265 lateral length with 46 stages per well. The average peak 24 hour production rate to sales, under constrained conditions was 35.1 Mmcfe per day per well, roughly twice the average rate of the offset pads. This is a result of refined completion designs, improved landing and longer laterals. On a normalized basis, average cost per well is
Production for the division in the fourth quarter of 2016, the first full quarter since the Memorial acquisition closing on
Since acquiring the assets, significant progress has been made operationally, including integration of personnel, information systems, communications systems and facilities. As mentioned on our third quarter conference call, Range has a new drilling team with extensive experience in high-pressure, high-temperature drilling conditions, including experience in the
As reported in late January, three wells were drilled and completed in the extension area prior to year-end. The wells were drilled on the north, east and west sides of the
Marketing and Transportation
Range’s overall marketing strategy for many years has been to assemble a diversified low-cost transportation portfolio. Recent developments are proving this to be a good strategy, with net pricing expected to improve on all products in 2017.
Natural gas pricing improved in the fourth quarter, with a full quarter of
Additionally, we have received favorable news regarding FERC authorizations on all remaining Appalachian takeaway projects on which Range holds capacity. Spectra’s Adair Southwest project received its final FERC Certificate in the fourth quarter providing incremental transportation out of the Appalachian basin starting in late 2017. TransCanada’s Leach and Rayne Express projects received their final FERC Certificates in January, with a projected in-service date in late 2017 as well. The combined capacity from these projects for Range is an additional 400,000 Mmbtu per day from the
Range’s gathering and processing costs per mcfe are expected to improve in coming years. In
NGL pricing has also improved recently on better domestic market fundamentals and the Company’s strong portfolio of domestic and international sales. As a result, Range’s calculated NGL prices (including ethane and processing costs) for 2017 increased to a range of 28% to 30% of WTI, based on current strip pricing. This approximate 2% increase in realizations would increase pre-hedge NGL revenue by approximately
Condensate prices have improved relative to WTI as well. Condensate differentials in the fourth quarter improved to less than
Financial Position and Liquidity
At
At
Guidance – 2017
Production per day Guidance
Production for the first quarter of 2017 is expected to be approximately 1.92 Bcfe per day with 30% to 32% liquids.
Production for the full year 2017 is expected to average approximately 2.07 Bcfe per day. This equates to a year-over-year growth rate of 33% to 35%.
1Q 2017 Expense Guidance
Direct operating expense: | $0.18 - $0.19 per mcfe |
Transportation, gathering, processing and compression expense: |
$1.00 - $1.04 per mcfe |
Production tax expense: | $0.05 - $0.07 per mcfe |
Exploration expense: | $12.0 - $13.0 million |
Unproved property impairment expense: | $6.0 - $8.0 million |
G&A expense: | $0.23 - $0.25 per mcfe |
Interest expense: | $0.26 - $0.28 per mcfe |
DD&A expense: | $0.88 - $0.90 per mcfe |
Net brokered gas marketing expense: | ~$2.0 million |
2017 Differentials
Based on current market pricing indications, Range expects to receive the following pre-hedge differentials for its production in 2017.
Natural Gas: | NYMEX minus $0.30 |
Natural Gas Liquids (including ethane): | 28% - 30% of WTI |
Oil/Condensate: | WTI minus $5.00 to $6.00 |
Hedging Status
Range hedges portions of its expected future production volumes to increase the predictability of cash flow and to help maintain a strong, flexible financial position. Range currently has over 75% of its expected 2017 natural gas production hedged at a weighted average floor price of
Range has also hedged Marcellus and other basis differentials to limit volatility between NYMEX and regional prices. The fair value of the basis hedges as of
Conference Call Information
A conference call to review the financial results is scheduled on
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
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 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, processing 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, processing 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, processing 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 reserve revisions, excluding PUD removals based on the
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
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 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.
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 merger integration, future well costs, expected asset sales, well productivity, future liquidity and financial resilience, anticipated exports and related financial impact, NGL market supply and demand, improving commodity fundamentals and pricing, future capital efficiencies, future shareholder value, emerging plays, capital spending, anticipated drilling and completion activity, acreage prospectivity, expected pipeline utilization 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. Further information on risks and uncertainties is available in Range's filings with the
The
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
2017-04
SOURCE:
RANGE RESOURCES CORPORATION | |||||||||||||||||||||||
STATEMENTS OF OPERATIONS | |||||||||||||||||||||||
Based on GAAP reported earnings with additional | |||||||||||||||||||||||
details of items included in each line in Form 10-K | |||||||||||||||||||||||
(Audited, in thousands, except per share data) | |||||||||||||||||||||||
Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||||||||||
2016 | 2015 | % | 2016 | 2015 | % | ||||||||||||||||||
Revenues and other income: | |||||||||||||||||||||||
Natural gas, NGLs and oil sales (a) | $ | 458,645 | $ | 254,043 | $ | 1,197,215 | $ | 1,089,644 | |||||||||||||||
Derivative fair value (loss)/income | (250,057 | ) | 126,312 | (261,391 | ) | 416,364 | |||||||||||||||||
Brokered natural gas, marketing and other (b) | 44,774 | 30,100 | 163,219 | 90,922 | |||||||||||||||||||
ARO settlement gain (loss) (b) | 54 | 80 | 40 | 103 | |||||||||||||||||||
Other (b) | 106 | 192 | 856 | 1,035 | |||||||||||||||||||
Total revenues and other income | 253,522 | 410,727 | -38 | % | 1,099,939 | 1,598,068 | -31 | % | |||||||||||||||
Costs and expenses: | |||||||||||||||||||||||
Direct operating | 29,755 | 28,757 | 95,086 | 133,583 | |||||||||||||||||||
Direct operating – non-cash stock-based compensation (c) | 521 | 631 | 2,302 | 2,780 | |||||||||||||||||||
Transportation, gathering, processing and compression | 164,338 | 112,481 | 565,209 | 396,739 | |||||||||||||||||||
Production and ad valorem taxes | 6,790 | 7,354 | 25,443 | 33,860 | |||||||||||||||||||
Brokered natural gas and marketing | 46,095 | 34,553 | 166,851 | 113,734 | |||||||||||||||||||
Brokered natural gas and marketing – non-cash stock-based compensation (c) |
376 | 389 | 1,725 | 2,132 | |||||||||||||||||||
Exploration | 13,055 | 3,446 | 30,027 | 18,421 | |||||||||||||||||||
Exploration – non-cash stock-based compensation (c) | 629 | 814 | 2,298 | 2,985 | |||||||||||||||||||
Abandonment and impairment of unproved properties | 6,307 | 11,432 | 30,076 | 47,619 | |||||||||||||||||||
General and administrative | 44,285 | 29,476 | 132,104 | 136,290 | |||||||||||||||||||
General and administrative – non-cash stock-based compensation (c) |
11,611 | 11,142 | 49,293 | 49,687 | |||||||||||||||||||
General and administrative – lawsuit settlements | 1,131 | 1,226 | 2,575 | 3,238 | |||||||||||||||||||
General and administrative – bad debt expense | — | 1,700 | 800 | 2,300 | |||||||||||||||||||
General and administrative – DEP penalty | — | — | — | 2,500 | |||||||||||||||||||
Memorial merger expenses | 813 | — | 37,225 | — | |||||||||||||||||||
Termination costs | (822 | ) | 10,283 | (519 | ) | 14,853 | |||||||||||||||||
Termination costs – non-cash stock-based compensation (c) | — | (1,503 | ) | — | 217 | ||||||||||||||||||
Deferred compensation plan (d) | (11,013 | ) | (21,016 | ) | 19,153 | (77,627 | ) | ||||||||||||||||
Interest expense | 46,749 | 40,849 | 168,213 | 166,439 | |||||||||||||||||||
Loss on early extinguishment of debt | — | — | — | 22,495 | |||||||||||||||||||
Depletion, depreciation and amortization | 149,662 | 127,977 | 524,102 | 581,155 | |||||||||||||||||||
Impairment of proved properties and other assets | — | 87,941 | 43,040 | 590,174 | |||||||||||||||||||
(Gain) loss on sale of assets | (470 | ) | 408,909 | 7,074 | 406,856 | ||||||||||||||||||
Total costs and expenses | 509,812 | 896,841 | -43 | % | 1,902,077 | 2,650,430 | -28 | % | |||||||||||||||
Loss before income taxes | (256,290 | ) | (486,114 | ) | 47 | % | (802,138 | ) | (1,052,362 | ) | 24 | % | |||||||||||
Income tax benefit: | |||||||||||||||||||||||
Current | 98 | 29 | 98 | 29 | |||||||||||||||||||
Deferred | (95,679 | ) | (164,316 | ) | (280,848 | ) | (338,706 | ) | |||||||||||||||
(95,581 | ) | (164,287 | ) | (280,750 | ) | (338,677 | ) | ||||||||||||||||
Net loss | $ | (160,709 | ) | $ | (321,827 | ) | 50 | % | $ | (521,388 | ) | $ | (713,685 | ) | 27 | % | |||||||
Net Loss Per Common Share: | |||||||||||||||||||||||
Basic | $ | (0.66 | ) | $ | (1.93 | ) | $ | (2.75 | ) | $ | (4.29 | ) | |||||||||||
Diluted | $ | (0.66 | ) | $ | (1.93 | ) | $ | (2.75 | ) | $ | (4.29 | ) | |||||||||||
Weighted average common shares outstanding, as reported: | |||||||||||||||||||||||
Basic | 244,362 | 166,573 | 47 | % | 189,868 | 166,389 | 14 | % | |||||||||||||||
Diluted | 244,362 | 166,573 | 47 | % | 189,868 | 166,389 | 14 | % |
(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.
RANGE RESOURCES CORPORATION | |||||||
BALANCE SHEETS | |||||||
(Audited, In thousands) | December 31, | December 31, | |||||
2016 | 2015 | ||||||
Assets | |||||||
Current assets | $ | 268,605 | $ | 157,530 | |||
Derivative assets | 13,483 | 288,762 | |||||
Goodwill | 1,654,292 | — | |||||
Natural gas and oil properties, successful efforts method | 9,256,337 | 6,361,305 | |||||
Transportation and field assets | 16,873 | 19,455 | |||||
Other | 72,655 | 72,979 | |||||
$ | 11,282,245 | $ | 6,900,031 | ||||
Liabilities and Stockholders’ Equity | |||||||
Current liabilities | $ | 530,373 | $ | 335,513 | |||
Asset retirement obligations | 7,271 | 15,071 | |||||
Derivative liabilities | 165,009 | 1,136 | |||||
Bank debt | 876,428 | 86,427 | |||||
Senior notes | 2,848,591 | 738,101 | |||||
Senior subordinated notes | 48,498 | 1,826,775 | |||||
Total debt | 3,773,517 | 2,651,303 | |||||
Deferred tax liability | 943,343 | 777,947 | |||||
Derivative liabilities | 24,491 | 21 | |||||
Deferred compensation liability | 119,231 | 104,792 | |||||
Asset retirement obligations and other liabilities | 310,642 | 254,590 | |||||
Common stock and retained earnings | 5,409,577 | 2,761,903 | |||||
Common stock held in treasury stock | (1,209 | ) | (2,245 | ) | |||
Total stockholders’ equity | 5,408,368 | 2,759,658 | |||||
$ | 11,282,245 | $ | 6,900,031 | ||||
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, | |||||||||||||||||||||
2016 | 2015 | % | 2016 | 2015 | % | |||||||||||||||||
Total revenues and other income, as reported | $ | 253,522 | $ | 410,727 | -38 | % | $ | 1,099,939 | $ | 1,598,068 | -31 | % | ||||||||||
Adjustment for certain special items: | ||||||||||||||||||||||
Total change in fair value related to derivatives prior to settlement loss | 336,736 | 45,165 | 608,727 | 115,758 | ||||||||||||||||||
ARO settlement (gain) loss | (54 | ) | (80 | ) | (40 | ) | (103 | ) | ||||||||||||||
Total revenues, as adjusted, non-GAAP | $ | 590,204 | $ | 455,812 | 30 | % | $ | 1,708,626 | $ | 1,713,723 | 0 | % | ||||||||||
RANGE RESOURCES CORPORATION | |||||||||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES | |||||||||||||||||
(Unaudited in thousands) | |||||||||||||||||
Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||||||||
Net loss | $ | (162,771 | ) | $ | (321,827 | ) | $ | (521,388 | ) | $ | (713,685 | ) | |||||
Adjustments to reconcile net cash provided from continuing operations: | |||||||||||||||||
Deferred income tax benefit | (93,617 | ) | (164,316 | ) | (280,848 | ) | (338,706 | ) | |||||||||
Depletion, depreciation, amortization and impairment | 149,662 | 215,918 | 567,142 | 1,171,329 | |||||||||||||
Exploration dry hole costs | 16 | 1 | 18 | 88 | |||||||||||||
Abandonment and impairment of unproved properties | 6,307 | 11,432 | 30,076 | 47,619 | |||||||||||||
Derivative fair value loss (income) | 250,057 | (126,312 | ) | 261,391 | (416,364 | ) | |||||||||||
Cash settlements on derivative financial instruments that do not qualify for hedge accounting | 86,679 | 171,477 | 347,336 | 532,122 | |||||||||||||
Allowance for bad debts | — | 1,700 | 800 | 2,300 | |||||||||||||
Amortization of deferred issuance costs, loss on extinguishment of debt and other | 1,787 | 1,811 | 7,170 | 29,383 | |||||||||||||
Deferred and stock-based compensation | 1,996 | (9,732 | ) | 74,685 | (20,411 | ) | |||||||||||
(Gain) loss on sale of assets and other | (470 | ) | 408,909 | 7,074 | 406,856 | ||||||||||||
Changes in working capital: | |||||||||||||||||
Accounts receivable | (52,571 | ) | (14,744 | ) | (20,586 | ) | 64,704 | ||||||||||
Inventory and other | 6,996 | (7,795 | ) | 6,220 | (14,868 | ) | |||||||||||
Accounts payable | 14,009 | (13,039 | ) | (27,259 | ) | (26,197 | ) | ||||||||||
Accrued liabilities and other | (23,049 | ) | 22,359 | (64,763 | ) | (32,768 | ) | ||||||||||
Net changes in working capital | (54,615 | ) | (13,219 | ) | (106,388 | ) | (9,129 | ) | |||||||||
Net cash provided from operating activities | $ | 185,031 | $ | 175,842 | $ | 387,068 | $ | 691,402 | |||||||||
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, | ||||||||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||||||||
Net cash provided from operating activities, as reported | $ | 185,031 | $ | 175,842 | $ | 387,068 | $ | 691,402 | |||||||||
Net changes in working capital | 54,615 | 13,219 | 106,388 | 9,129 | |||||||||||||
Exploration expense | 13,039 | 3,445 | 30,009 | 18,333 | |||||||||||||
Lawsuit settlements | 1,131 | 1,226 | 2,575 | 3,238 | |||||||||||||
Cash paid to exchange senior subordinated notes | — | — | 6,600 | — | |||||||||||||
Legal contingency/DEP penalty | — | — | — | 2,500 | |||||||||||||
Memorial merger expenses | 813 | — | 37,225 | — | |||||||||||||
Termination costs | (822 | ) | 10,283 | (519 | ) | 14,853 | |||||||||||
Non-cash compensation adjustment | 56 | 73 | 19 | 709 | |||||||||||||
Cash flow from operations before changes in working capital – non-GAAP measure | $ | 253,863 | $ | 204,088 | $ | 569,365 | $ | 740,164 | |||||||||
ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING | |||||||||||||||||
(Unaudited, in thousands) | |||||||||||||||||
Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||||||||
Basic: | |||||||||||||||||
Weighted average shares outstanding | 247,161 | 169,371 | 192,661 | 169,183 | |||||||||||||
Stock held by deferred compensation plan | (2,799 | ) | (2,798 | ) | (2,793 | ) | (2,794 | ) | |||||||||
Adjusted basic | 244,362 | 166,573 | 189,868 | 166,389 | |||||||||||||
Dilutive: | |||||||||||||||||
Weighted average shares outstanding | 247,161 | 169,371 | 192,661 | 169,183 | |||||||||||||
Dilutive stock options under treasury method | (2,799 | ) | (2,798 | ) | (2,793 | ) | (2,794 | ) | |||||||||
Adjusted dilutive | 244,362 | 166,573 | 189,868 | 166,389 | |||||||||||||
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, PROCESSING AND COMPRESSION FEES, a non-GAAP measure | ||||||||||||||||||||||
(Unaudited, in thousands, except per unit data) | ||||||||||||||||||||||
Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||||||||
2016 | 2015 | % | 2016 | 2015 | % | |||||||||||||||||
Natural gas, NGLs and oil sales components: | ||||||||||||||||||||||
Natural gas sales | $ | 289,790 | $ | 183,576 | $ | 753,888 | $ | 773,093 | ||||||||||||||
NGLs sales | 119,585 | 44,724 | 318,462 | 176,546 | ||||||||||||||||||
Oil sales | 49,270 | 25,743 | 124,865 | 140,005 | ||||||||||||||||||
Total natural gas, NGL sales, as reported | $ | 458,645 | $ | 254,043 | 81 | % | $ | 1,197,215 | $ | 1,089,644 | 10 | % | ||||||||||
Derivative fair value income (loss), as reported: | $ | (250,057 | ) | $ | 126,312 | $ | (261,391 | ) | $ | 416,364 | ||||||||||||
Cash settlements on derivative financial instruments – (gain) loss: | ||||||||||||||||||||||
Natural gas | (46,015 | ) | (115,428 | ) | (252,000 | ) | (339,031 | ) | ||||||||||||||
NGLs | (22,231 | ) | (10,366 | ) | (47,626 | ) | (41,974 | ) | ||||||||||||||
Crude Oil | (18,433 | ) | (45,683 | ) | (47,710 | ) | (151,117 | ) | ||||||||||||||
Total change in fair value related to derivatives prior to settlement, a non-GAAP measure | $ | (336,736 | ) | $ | (45,165 | ) | $ | (608,727 | ) | $ | (115,758 | ) | ||||||||||
Transportation, gathering, processing and compression components: | ||||||||||||||||||||||
Natural gas | $ | 114,854 | $ | 95,849 | $ | 403,209 | $ | 343,593 | ||||||||||||||
NGLs | 49,484 | 16,632 | 162,000 | 53,146 | ||||||||||||||||||
Total transportation, gathering, processing and compression, as reported | $ | 164,338 | $ | 112,481 | $ | 565,209 | $ | 396,739 | ||||||||||||||
Natural gas, NGL and oil sales, including cash-settled derivatives: (c) | ||||||||||||||||||||||
Natural gas sales | $ | 335,805 | $ | 299,004 | $ | 1,005,888 | $ | 1,112,124 | ||||||||||||||
NGLs sales | 141,816 | 55,090 | 366,088 | 218,520 | ||||||||||||||||||
Oil sales | 67,703 | 71,426 | 172,575 | 291,122 | ||||||||||||||||||
Total | $ | 545,324 | $ | 425,520 | 28 | % | $ | 1,544,551 | $ | 1,621,766 | -5 | % | ||||||||||
Production of oil and gas during the periods (a): | ||||||||||||||||||||||
Natural gas (mcf) | 114,480,336 | 97,175,602 | 18 | % | 375,811,462 | 362,686,707 | 4 | % | ||||||||||||||
NGLs (bbl) | 8,245,792 | 4,906,615 | 68 | % | 27,825,635 | 20,356,110 | 37 | % | ||||||||||||||
Oil (bbl) | 1,104,414 | 897,064 | 23 | % | 3,609,171 | 4,084,069 | -12 | % | ||||||||||||||
Gas equivalent (mcfe) (b) | 170,581,572 | 131,997,676 | 29 | % | 564,420,298 | 509,327,781 | 11 | % | ||||||||||||||
Production of oil and gas – average per day (a): | ||||||||||||||||||||||
Natural gas (mcf) | 1,244,351 | 1,056,257 | 18 | % | 1,026,807 | 993,662 | 3 | % | ||||||||||||||
NGLs (bbl) | 89,628 | 53,333 | 68 | % | 76,026 | 55,770 | 36 | % | ||||||||||||||
Oil (bbl) | 12,005 | 9,751 | 23 | % | 9,861 | 11,189 | -12 | % | ||||||||||||||
Gas equivalent (mcfe) (b) | 1,854,148 | 1,434,757 | 29 | % | 1,542,132 | 1,395,419 | 11 | % | ||||||||||||||
Average prices, including cash-settled hedges that qualify for hedge accounting before third party transportation costs: | ||||||||||||||||||||||
Natural gas (mcf) | $ | 2.53 | $ | 1.89 | 34 | % | $ | 2.01 | $ | 2.13 | -6 | % | ||||||||||
NGLs (bbl) | $ | 14.50 | $ | 9.12 | 59 | % | $ | 11.44 | $ | 8.67 | 32 | % | ||||||||||
Oil (bbl) | $ | 44.61 | $ | 28.70 | 55 | % | $ | 34.60 | $ | 34.28 | 1 | % | ||||||||||
Gas equivalent (mcfe) (b) | $ | 2.69 | $ | 1.92 | 40 | % | $ | 2.12 | $ | 2.14 | -1 | % | ||||||||||
Average prices, including cash-settled hedges and derivatives before third party transportation costs: (c) | ||||||||||||||||||||||
Natural gas (mcf) | $ | 2.93 | $ | 3.08 | -5 | % | $ | 2.68 | $ | 3.07 | -13 | % | ||||||||||
NGLs (bbl) | $ | 17.20 | $ | 11.23 | 53 | % | $ | 13.16 | $ | 10.73 | 23 | % | ||||||||||
Oil (bbl) | $ | 61.30 | $ | 79.62 | -23 | % | $ | 47.82 | $ | 71.28 | -33 | % | ||||||||||
Gas equivalent (mcfe) (b) | $ | 3.20 | $ | 3.22 | -1 | % | $ | 2.74 | $ | 3.18 | -14 | % | ||||||||||
Average prices, including cash-settled hedges and derivatives: (d) | ||||||||||||||||||||||
Natural gas (mcf) | $ | 1.93 | $ | 2.09 | -8 | % | $ | 1.60 | $ | 2.12 | -24 | % | ||||||||||
NGLs (bbl) | $ | 11.20 | $ | 7.84 | 43 | % | $ | 7.33 | $ | 8.12 | -10 | % | ||||||||||
Oil (bbl) | $ | 61.30 | $ | 79.62 | -23 | % | $ | 47.82 | $ | 71.28 | -33 | % | ||||||||||
Gas equivalent (mcfe) (b) | $ | 2.23 | $ | 2.37 | -6 | % | $ | 1.74 | $ | 2.41 | -28 | % | ||||||||||
Transportation, gathering, processing and compression expense per mcfe | $ | 0.96 | $ | 0.85 | 13 | % | $ | 1.00 | $ | 0.78 | 29 | % |
(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, processing and compression costs.
(d) Net of transportation, gathering, processing and compression costs.
RANGE RESOURCES CORPORATION | |||||||||||||||||||||
RECONCILIATION OF INCOME BEFORE INCOME TAXES AS REPORTED TO INCOME 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, | ||||||||||||||||||||
2016 | 2015 | % | 2016 | 2015 | % | ||||||||||||||||
Loss from operations before income taxes, as reported | $ | (256,290 | ) | $ | (486,114 | ) | 47 | % | $ | (802,138 | ) | $ | (1,052,362 | ) | -24 | % | |||||
Adjustment for certain special items: | |||||||||||||||||||||
(Gain) loss on sale of assets | (470 | ) | 408,909 | 7,074 | 406,856 | ||||||||||||||||
(Gain) loss on ARO settlements | (54 | ) | (80 | ) | (40 | ) | (103 | ) | |||||||||||||
Change in fair value related to derivatives prior to settlement | 336,736 | 45,165 | 608,727 | 115,758 | |||||||||||||||||
Abandonment and impairment of unproved properties | 6,307 | 11,432 | 30,076 | 47,619 | |||||||||||||||||
Loss on early extinguishment of debt | — | — | — | 22,495 | |||||||||||||||||
Impairment of proved property | — | 87,941 | 43,040 | 590,174 | |||||||||||||||||
Lawsuit settlements | 1,131 | 1,226 | 2,575 | 3,238 | |||||||||||||||||
Fees paid to exchange senior subordinated notes | — | — | 6,600 | — | |||||||||||||||||
DEP penalty | — | — | — | 2,500 | |||||||||||||||||
Memorial merger expenses | 813 | — | 37,225 | — | |||||||||||||||||
Termination costs | (822 | ) | 10,283 | (519 | ) | 14,853 | |||||||||||||||
Termination costs – non-cash stock-based compensation | — | (1,503 | ) | — | 217 | ||||||||||||||||
Brokered natural gas and marketing – non-cash stock-based compensation | 376 | 389 | 1,725 | 2,132 | |||||||||||||||||
Direct operating – non-cash stock-based compensation | 521 | 631 | 2,302 | 2,780 | |||||||||||||||||
Exploration expenses – non-cash stock-based compensation | 629 | 814 | 2,298 | 2,985 | |||||||||||||||||
General & administrative – non-cash stock-based compensation | 11,611 | 11,142 | 49,293 | 49,687 | |||||||||||||||||
Deferred compensation plan – non-cash adjustment | (11,013 | ) | (21,016 | ) | 19,153 | (77,627 | ) | ||||||||||||||
Income before income taxes, as adjusted | 89,475 | 69,219 | 29 | % | 7,391 | 131,202 | -94 | % | |||||||||||||
Income tax expense, as adjusted | |||||||||||||||||||||
Current | 98 | 29 | 98 | 29 | |||||||||||||||||
Deferred (a) | 33,759 | 27,431 | 2,426 | 50,777 | |||||||||||||||||
Net income excluding certain items, a non-GAAP measure | $ | 55,618 | $ | 41,759 | 33 | % | $ | 4,867 | $ | 80,396 | -94 | % | |||||||||
Non-GAAP income (loss) per common share | |||||||||||||||||||||
Basic | $ | 0.23 | $ | 0.25 | -8 | % | $ | 0.03 | $ | 0.48 | -94 | % | |||||||||
Diluted | $ | 0.23 | $ | 0.25 | -8 | % | $ | 0.03 | $ | 0.48 | -94 | % | |||||||||
Non-GAAP diluted shares outstanding, if dilutive | 244,761 | 166,881 | 189,911 | 166,432 | |||||||||||||||||
(a) Deferred taxes for 2016 are estimated to be approximately 38%.
RANGE RESOURCES CORPORATION | |||||||||||
HEDGING POSITION AS OF FEBRUARY 17, 2017 (Unaudited) – |
|||||||||||
Daily Volume | Hedge Price | ||||||||||
Gas | |||||||||||
2017 Swaps | 830,171 Mmbtu | $ | 3.17 | ||||||||
2017 Puts (1) | 175,890 Mmbtu | $ | 3.17 | ||||||||
2017 Collars | 117,123 Mmbtu | $ | 3.48 x $4.15 | ||||||||
1Q 2018 Swaps | 830,000 Mmbtu | $ | 3.42 | ||||||||
2Q-4Q 2018 Swaps | 225,000 Mmbtu | $ | 2.97 | ||||||||
Oil | |||||||||||
2017 Swaps | 8,795 bbls | $ | 55.81 | ||||||||
2018 Swaps | 3,000 bbls | $ | 54.36 | ||||||||
C2 Ethane | |||||||||||
2017 Swaps | 3,000 bbls | $ | 0.27/gallon | ||||||||
C3 Propane (2) | |||||||||||
2017 Swaps | 13,974 bbls | $ | 0.56/gallon | ||||||||
2018 Swaps | 7,199 bbls | $ | 0.61/gallon | ||||||||
C4 Normal Butane | |||||||||||
2017 Swaps | 7,731 bbls | $ | 0.74/gallon | ||||||||
2018 Swaps | 4,250 bbls | $ | 0.81/gallon | ||||||||
C5 Natural Gasoline | |||||||||||
2017 Swaps | 5,250 bbls | $ | 01.06/gallon | ||||||||
2017 Swaps | 1,500 bbls | $ | 01.19/gallon |
(1) Net of deferred premiums
(2) Incorporates international propane spreads
NOTE: SEE WEBSITE FOR OTHER SUPPLEMENTAL INFORMATION FOR THE PERIODS
Investor Contacts:Laith Sando , Vice President – Investor Relations 817-869-4267 lsando@rangeresources.comDavid Amend , Investor Relations Manager 817-869-4266 damend@rangeresources.comMichael Freeman , Senior Financial Analyst 817-869-4264 mfreeman@rangeresources.comJosh Stevens , Financial Analyst 817-869-1564 jrstevens@rangeresources.com Media Contact:Michael Mackin , Director of Public Affairs 724-873-3224 mmackin@rangeresources.com www.rangeresources.com