Range Announces Third Quarter 2015 Results
Highlights -
- Unit costs declined by
$0.36 per mcfe, or 12% compared to the prior-year quarter. - Production volumes averaged 1,445 Mmcfe per day, a 20% increase over the prior-year quarter.
- Marcellus production averaged 1,277 Mmcfe per day, a 27% increase over the prior-year quarter.
- First
Utica well inWashington County, Pennsylvania estimated to have 15 Bcf EUR, or 2.8 Bcf per 1,000 feet of lateral. - Second
Utica well brought online with choke management at 13 Mmcf per day rate and projected to have higher EUR than the first well. - Full-year 2015 capital budget of
$870 million is on track to deliver 20% annual year-over-year growth. - Mariner East I with full operations for propane and ethane expected by the end of the year.
Commenting,
"We are continuing to work on potential non-core asset sales for areas in our portfolio that cannot compete against the Marcellus for capital. Range expects to close one or more non-core asset sales prior to year-end. Any sales proceeds will be used to reduce debt and strengthen our balance sheet. Importantly, we are continuing to drive down costs and implement innovative marketing solutions that are expected to deliver improved margins. We also see signs of improved pricing ahead, especially in Appalachia, as the Mariner East I project becomes fully operational by year-end and completion of other infrastructure projects to move natural gas and NGLs out of the basin. Each of these projects is expected to improve the basis differentials in the southwest area of the Marcellus in the near-term. These projects, combined with the industry slowdown and reduction in capital spending, should help to bring supply and demand in balance both nationally and regionally, thus improving our prices and margins going forward."
Capital Expenditures
Third quarter drilling expenditures of
Operational Discussion
Range has updated its investor presentation with third quarter financial and operational results. Please see www.rangeresources.com under the "Investors" tab, "Company Presentations" area, for the presentation entitled, "Company Presentation -
Range has made significant improvements in capital efficiencies over the last four years as lateral lengths increased and completion techniques have been optimized. These improvements, combined with the added benefit of lower service costs, have lowered well cost per lateral foot about 60% in the Marcellus over that time frame. In addition to these industry leading well costs, Range also has some of the highest estimated ultimate recoveries ("EUR") on a normalized basis (per 1,000 feet of lateral). The table below shows the expected averages for the wells turned to sales in 2015.
Marcellus Area | Average EUR (Bcfe) |
Average Well Cost |
||
per 1,000 ft. | per 1,000 ft. | |||
SW Dry | 2.52 | $883,000 | ||
SW Wet | 2.95 | $991,000 | ||
SW Super rich | 2.40 | $1,100,000 | ||
NE Dry | 2.67 | $865,000 | ||
Southern Marcellus Shale Division -
Production for the third quarter averaged 999 net Mmcfe per day for the division, a 28% increase over the prior-year quarter. The division's third quarter net production included 635 Mmcf per day of gas, 51,967 barrels per day of NGLs and 8,676 barrels per day of condensate. During the third quarter, 23 wells were turned in line in southwest
During the third quarter, Range brought online a second Washington County Utica well, the Claysville Sportsman's Unit 9H. The well was completed with a lateral length of 5,228 feet, utilizing 32 stages. Both dry
During the third quarter, Range brought online 22 Marcellus wells, four in the super-rich area, 10 in the wet gas area and eight in the dry gas area. The 14 wells brought online in the wet and super-rich areas had a 24-hour IP average of 16.1 Mmcfe per day (6.6 Mmcf of gas, 1,179 barrels of NGLs and 404 barrels of condensate), from an average lateral length of 5,360 feet, utilizing 27 stages. In the dry gas area, the 24-hour IP averaged 15.7 Mmcf per day, from an average lateral length of 5,293 feet, utilizing 28 stages. Most of the facilities that Range is currently constructing are designed to limit initial flow, resulting in flatter initial production while achieving lower facility cost.
Northern Marcellus Shale Division -
In northeast
Southern Appalachia Division -
Production for the third quarter averaged 109 net Mmcf per day for the division, a 2% decrease compared to the prior-year, and flat with the second quarter. With the division's continued focus on maintaining production for the year, production for the division remained flat compared to the second quarter while only turning in line three wells. The division drilled one coalbed methane ("CBM") well and completed two additional wells in the third quarter 2015. The division continued using a new completion technique on CBM wells which resulted in the best group of CBM wells in the Nora field in over 25 years. In addition to these more efficient completions which have resulted in improved economics, Range also has the added economic benefit of owning the majority of the royalty and receiving a premium gas price due to the assets being in close proximity to the growing southeast markets.
Marcellus Shale Marketing and Transportation Update -
Commodity prices continued to be challenging in the third quarter, but Range expects improvement in the fourth quarter and 2016. Specifically, Range's marketing team has put in place numerous strategies that are now showing results. As anchor shipper on Spectra's
The Mariner East I project is scheduled to commence full operations by the end of the year. Our latest communications with
A key component of Range's marketing strategy for many years has focused on securing firm transportation capacity, at a reasonable cost, to access markets outside of the Appalachian basin. This strategy was implemented many years ago, when Range realized that Marcellus volumes would quickly exceed the historical pipeline infrastructure and local demand. As a result, Range was able to assemble a diversified portfolio of firm transportation projects at low-cost that corresponds to its expected Appalachian volumes. Range believes that pipeline infrastructure construction will likely exceed the gas volumes expected to be moved out of Appalachia. This added capacity will be available in the secondary market as producers are not expected to satisfy all of their volume commitments, providing excess capacity in the takeaway pipelines. With the slowdown in capital spending expected for 2016, the availability and amount of excess capacity may occur earlier and greater than expected. As producers are able to flow more gas out of the basin, basis differentials in Appalachia are expected to improve.
In the
Financial Discussion
(Except for generally accepted accounting principles ("GAAP") reported amounts, specific expense categories exclude non-cash impairments, derivative fair value income/(loss), non-cash stock compensation and other items shown separately on the attached tables. "Total unit costs" as used in this release are composed of direct operating, transportation, gathering and compression, production and ad valorem tax, general and administrative, interest and depletion, depreciation and amortization costs divided by production as shown on the attached tables. "Total unit cash costs" are the same as "Total unit costs" except depletion, depreciation and amortization cost is excluded. See "Non-GAAP Financial Measures" for a definition of each of the non-GAAP financial measures and the tables that reconcile each of the non-GAAP measures to their most directly comparable GAAP financial measure.)
GAAP revenues for the third quarter of 2015 totaled
Non-GAAP revenues for third quarter 2015 totaled
Expenses | 2Q 2015 (per mcfe) | 3Q 2015 (per mcfe) | 3Q 2014 (per mcfe) | YOY Increase (Decrease) | |||||||
Direct operating | $ | 0.27 | $ | 0.26 | $ | 0.33 | -21% | ||||
Transportation, gathering and compression | 0.76 | 0.75 | 0.76 | -1% | |||||||
Production and ad valorem taxes | 0.07 | 0.06 | 0.09 | -33% | |||||||
General and administrative | 0.30 | 0.25 | 0.34 | -26% | |||||||
Interest | 0.35 | 0.32 | 0.35 | -9% | |||||||
$ | 1.75 | $ | 1.64 | $ | 1.87 | -12% | |||||
Depletion, depreciation and amortization | 1.21 | 1.16 | 1.28 | -9% | |||||||
$ | 2.97 (a) | $ | 2.79 (a) | $ | 3.16 (a) | -12% | |||||
(a) Amounts may not add due to rounding. | |||||||||||
Third 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
- Production and realized prices for each commodity for the third quarter of 2015 without the effect of hedging were: natural gas - 1,057 Mmcf per day (
$1.94 per mcf); NGLs - 54,186 barrels per day ($6.23 per barrel) and crude oil and condensate - 10,420 barrels per day ($33.26 per barrel). - The third quarter average natural gas price decreased to
$2.77 per mcf (including the impact of cash-settled hedges), as compared to the prior-year quarter of$3.63 per mcf. Financial hedges based upon NYMEX increased realizations$0.79 per mcf while financial basis hedges increased realizations$0.04 per mcf during the third quarter. The average Company natural gas differential including the settled financial basis hedges but before NYMEX hedging for the third quarter was($0.78) per mcf, compared to($0.49) per mcf in the prior-year quarter. - Total NGL pricing per barrel including ethane and processing expenses after realized cash-settled hedging was
$9.45 for the third quarter compared to$22.53 per barrel in the prior-year quarter. Hedging increased NGL prices by$3.22 per barrel in the third quarter compared to$0.27 in the prior-year quarter. Our gross Marcellus C3+ NGL barrel (without ethane) including realized hedges for the third quarter was approximately$17.15 per barrel. - Crude oil and condensate price realizations, before realized hedges, for the third quarter averaged
$13.35 below West Texas Intermediate ("WTI"), or$33.26 per barrel; compared to$16.17 per barrel below WTI in the second quarter of 2015, a 17% improvement and$15.65 per barrel below WTI in the prior-year quarter, a 15% improvement. Hedging for the third quarter added$42.99 per barrel compared to a loss of$2.68 in the prior-year.
Financial Position and Liquidity
On
As of
Guidance - Fourth Quarter 2015
Production Guidance:
Production growth for 2015 is targeted at 20% year-over-year. Average daily production for the fourth quarter of 2015 is expected to be approximately 1.42 Bcfe per day with approximately 26% liquids, without any incremental volumes associated with the Mariner East I start-up.
Expense per mcfe Guidance:
Direct operating expense: | $0.27 - $0.29 per mcfe | |
Transportation, gathering and compression expense: | $0.79 - $0.81 per mcfe | |
Production tax expense: | $0.07 - $0.08 per mcfe | |
Exploration expense: | $6 - $8 million | |
Unproved property impairment expense: | $11 - $13 million | |
G&A expense: | $0.26 - $0.28 per mcfe | |
Interest expense: | $0.32 - $0.33 per mcfe | |
DD&A expense: | $1.15 - $1.17 per mcfe |
Based on historical trends, base net expense for brokered natural gas and marketing activity is expected to be
Guidance for Remaining 2015 Activity:
Unchanged from the previous quarter, Range expects to turn in line 169 wells during 2015, as shown below. The number of wells expected to be turned in line has slowed in the fourth quarter of the year, reflecting capital spent and rig counts being weighted to the first half of the current year.
Wells turned in line - First 9 Months 2015 |
Expected remaining wells to turn in line- 4th Quarter 2015 |
Total planned wells to turn in line for 2015 | ||||||
Super-Rich area | 25 | 0 | 25 | |||||
Wet area | 49 | 8 | 57 | |||||
Dry- SW | 25 | 9 | 34 | |||||
Dry- NE | 17 | 0 | 17 | |||||
Total Marcellus/Utica | 116 | 17 | 133 | |||||
Nora area | 24 | 1 | 25 | |||||
Midcontinent | 11 | 0 | 11 | |||||
Total | 151 | 18 | 169 | |||||
NYMEX Hedging Status
Range hedges portions of its expected future production volumes to increase the predictability of cash flow and to help maintain a strong, flexible financial position. Range currently has approximately 85% of its remaining 2015 natural gas production hedged at a weighted average floor price of
For calendar year 2016, Range has hedged 630,000 Mmbtu per day of its expected natural gas production at a weighted average price of
Basis Hedging Status
In addition to the collars and swaps above, at
Conference Call Information
A conference call to review the financial results is scheduled on
A simultaneous webcast of the call may be accessed over the Internet at www.rangeresources.com. The webcast will be archived for replay on the Company's website until
Non-GAAP Financial Measures:
Adjusted net income comparable to analysts' estimates as set forth in this release (sometimes referred to as "Adjusted net income") 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 is comparable to analysts' estimates and is calculated on the same basis as analysts' estimates. We believe that many investors use this published research in making investment decisions and in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. "Diluted earnings per share (adjusted)" as set forth in this release represents Adjusted net income comparable to analysts' estimates on a diluted per share basis. A table is included which reconciles income or loss from operations to Adjusted net income comparable to analysts' estimates and Diluted earnings per share (adjusted). On its website, the Company provides additional comparative information on prior periods along with non-GAAP revenue disclosures.
Cash flow from operations before changes in working capital (sometimes referred to as "Adjusted cash flow") as defined in this release represents net cash provided by operations before changes in working capital and exploration expense adjusted for certain non-cash compensation items. Cash flow from operations before changes in working capital is widely accepted by the investment community as a financial indicator of an oil and gas company's ability to generate cash to internally fund exploration and development activities and to service debt. Cash flow from operations before changes in working capital is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Cash flow from operations before changes in working capital is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operations, investing, or financing activities as an indicator of cash flows, or as a measure of liquidity. A table is included which reconciles Net cash provided by operations to Cash flow from operations before changes in working capital as used in this release. On its website, the Company provides additional comparative information on prior periods for cash flow, cash margins and non-GAAP earnings as used in this release.
The cash prices realized for oil and natural gas production including the amounts realized on cash-settled derivatives and net of transportation, gathering and compression expense is a critical component in the Company's performance tracked by investors and professional research analysts in valuing, comparing, rating and providing investment recommendations and forecasts of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Due to the GAAP disclosures of various derivative transactions and third party transportation, gathering and compression expense, such information is now reported in various lines of the income statement. The Company believes that it is important to furnish a table reflecting the details of the various components of each income statement line to better inform the reader of the details of each amount and provide a summary of the realized cash-settled amounts and third party transportation, gathering and compression expense which historically were reported as natural gas, NGLs and oil sales. This information will serve to bridge the gap between various readers' understanding and fully disclose the information needed.
The Company discloses in this release the detailed components of many of the single line items shown in the unaudited GAAP financial statements included in the Company's Quarterly Report on Form 10-Q. The Company believes that it is important to furnish this detail of the various components comprising each line of the Statements of Operations to better inform the reader of the details of each amount, the changes between periods and the effect on its financial results.
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, future production growth, future completion of ethane projects, estimated gas in place, future rates of return, future low costs, low reinvestment risk, future earnings and per-share value, future capital spending plans, increasing capital efficiency, 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, future market improvements, maximizing future rates of return, strong inventory of uncompleted wells, expectation to create future value, expected lower well costs, acreage prospective for other horizons, expected future asset sales and future guidance information are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These statements are based on assumptions and estimates that management believes are reasonable based on currently available information; however, management's assumptions and Range's future performance are subject to a wide range of business risks and uncertainties and there is no assurance that these goals and projections can or will be met. Any number of factors could cause actual results to differ materially from those in the forward-looking statements, including, but not limited to, the volatility of oil and gas prices, the results of our hedging transactions, the costs and results of actual drilling and operations, the timing of production, mechanical and other inherent risks associated with oil and gas production, weather, the availability of drilling equipment, changes in interest rates, litigation, uncertainties about reserve estimates, environmental risks and regulatory changes. Range undertakes no obligation to publicly update or revise any forward-looking statements. Further information on risks and uncertainties is available in Range's filings with the
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
RANGE RESOURCES CORPORATION |
STATEMENTS OF OPERATIONS |
Based on GAAP reported earnings with additional details of items included in each line in Form 10-Q |
(Unaudited, in thousands, except per share data) |
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||
2015 | 2014 | % | 2015 | 2014 | % | |||||||||||||||||||
Revenues and other income: | ||||||||||||||||||||||||
Natural gas, NGLs and oil sales (a) | $ | 252,065 | $ | 446,067 | $ | 835,601 | $ | 1,495,601 | ||||||||||||||||
Derivative fair value income/(loss) | 202,004 | 142,057 | 290,052 | (28,902 | ) | |||||||||||||||||||
(Loss) gain on sale of assets | (681 | ) | 167 | 2,053 | 281,878 | |||||||||||||||||||
Brokered natural gas, marketing and other (b) | 25,141 | 28,118 | 60,822 | 91,641 | ||||||||||||||||||||
Equity method investment (b) | - | - | - | (277 | ) | |||||||||||||||||||
ARO settlement (loss) gain (b) | (5 | ) | 135 | 23 | (651 | ) | ||||||||||||||||||
Other (b) | 728 | 71 | 843 | 191 | ||||||||||||||||||||
Total revenues and other income | 479,252 | 616,615 | -22 | % | 1,189,394 | 1,839,481 | -35 | % | ||||||||||||||||
Costs and expenses: | ||||||||||||||||||||||||
Direct operating | 34,449 | 37,072 | 104,826 | 109,013 | ||||||||||||||||||||
Direct operating - non-cash stock-based compensation (c) | 609 | 720 | 2,149 | 3,509 | ||||||||||||||||||||
Transportation, gathering and compression | 99,634 | 84,777 | 284,258 | 235,747 | ||||||||||||||||||||
Production and ad valorem taxes | 7,336 | 10,110 | 26,506 | 32,632 | ||||||||||||||||||||
Brokered natural gas and marketing | 31,713 | 28,050 | 79,181 | 95,296 | ||||||||||||||||||||
Brokered natural gas and marketing - non-cash stock- | 618 | 656 | 1,743 | 2,314 | ||||||||||||||||||||
based compensation (c) | ||||||||||||||||||||||||
Exploration | 3,547 | 10,410 | 14,975 | 36,502 | ||||||||||||||||||||
Exploration - non-cash stock-based compensation (c) | 688 | 1,033 | 2,171 | 3,408 | ||||||||||||||||||||
Abandonment and impairment of unproved properties | 12,366 | 13,444 | 36,187 | 32,771 | ||||||||||||||||||||
General and administrative | 33,038 | 37,255 | 106,814 | 109,854 | ||||||||||||||||||||
General and administrative - non-cash stock-based | 11,512 | 11,556 | 38,545 | 43,856 | ||||||||||||||||||||
compensation (c) | ||||||||||||||||||||||||
General and administrative - lawsuit settlements | 1,278 | 1,252 | 2,012 | 2,203 | ||||||||||||||||||||
General and administrative - bad debt expense | 350 | - | 600 | 250 | ||||||||||||||||||||
General and administrative - legal contingency | - | 4,900 | 2,500 | 4,900 | ||||||||||||||||||||
(DEP penalty in prior year) | ||||||||||||||||||||||||
Termination costs | (76 | ) | - | 4,570 | - | |||||||||||||||||||
Termination costs - non-cash stock-based compensation (c) | (1 | ) | - | 1,720 | - | |||||||||||||||||||
Deferred compensation plan (d) | (43,705 | ) | (46,198 | ) | (56,611 | ) | (37,714 | ) | ||||||||||||||||
Interest expense | 42,904 | 39,188 | 125,590 | 130,077 | ||||||||||||||||||||
Loss on early extinguishment of debt | 22,495 | - | 22,495 | 24,596 | ||||||||||||||||||||
Depletion, depreciation and amortization | 153,993 | 142,450 | 453,178 | 404,493 | ||||||||||||||||||||
Impairment of proved properties and other assets | 502,233 | - | 502,233 | 24,991 | ||||||||||||||||||||
Total costs and expenses | 914,981 | 376,675 | 143 | % | 1,755,642 | 1,258,698 | 39 | % | ||||||||||||||||
(Loss) income before income taxes | (435,729 | ) | 239,940 | -282 | % | (566,248 | ) | 580,783 | -197 | % | ||||||||||||||
Income tax (benefit) expense: | ||||||||||||||||||||||||
Current | - | - | - | 5 | ||||||||||||||||||||
Deferred | (134,781 | ) | 93,522 | (174,390 | ) | 230,450 | ||||||||||||||||||
(134,781 | ) | 93,522 | (174,390 | ) | 230,455 | |||||||||||||||||||
Net (loss) income | $ | (300,948 | ) | $ | 146,418 | -306 | % | $ | (391,858 | ) | $ | 350,328 | -212 | % | ||||||||||
Net (Loss) Income Per Common Share: | ||||||||||||||||||||||||
Basic | $ | (1.81 | ) | $ | 0.87 | $ | (2.36 | ) | $ | 2.11 | ||||||||||||||
Diluted | $ | (1.81 | ) | $ | 0.86 | $ | (2.36 | ) | $ | 2.10 | ||||||||||||||
Weighted average common shares outstanding, as reported: | ||||||||||||||||||||||||
Basic | 166,517 | 165,841 | 0 | % | 166,327 | 162,866 | 2 | % | ||||||||||||||||
Diluted | 166,517 | 166,460 | 0 | % | 166,327 | 163,685 | 2 | % | ||||||||||||||||
(a) | See separate natural gas, NGLs and oil sales information table. | |
(b) | Included in Brokered natural gas, marketing and other revenues in the 10-Q. | |
(c) | Costs associated with stock compensation and restricted stock amortization, which have been reflected in the categories associated with the direct | |
personnel costs, which are combined with the cash costs in the 10-Q. | ||
(d) | Reflects the change in market value of the vested Company stock held in the deferred compensation plan. | |
RANGE RESOURCES CORPORATION |
||||||||||
BALANCE SHEETS | ||||||||||
(In thousands) | September 30, | December 31, | ||||||||
2015 | 2014 | |||||||||
(Unaudited) | (Audited) | |||||||||
Assets | ||||||||||
Current assets | $ | 134,320 | $ | 207,243 | ||||||
Derivative assets - current | 289,108 | 363,049 | ||||||||
Natural gas and oil properties, successful efforts method | 7,784,794 | 7,977,573 | ||||||||
Transportation and field assets | 29,835 | 37,581 | ||||||||
Other | 159,847 | 161,334 | ||||||||
$ | 8,397,904 | $ | 8,746,780 | |||||||
Liabilities and Stockholders' Equity | ||||||||||
Current liabilities | $ | 447,830 | $ | 740,197 | ||||||
Asset retirement obligations | 17,689 | 15,067 | ||||||||
Derivative liabilities | 293 | - | ||||||||
Bank debt | 987,000 | 723,000 | ||||||||
Senior notes | 750,000 | - | ||||||||
Senior subordinated notes | 1,850,000 | 2,350,000 | ||||||||
3,587,000 | 3,073,000 | |||||||||
Deferred tax liability | 843,189 | 997,494 | ||||||||
Derivative liabilities | 111 | - | ||||||||
Deferred compensation liability | 117,137 | 178,599 | ||||||||
Asset retirement obligations and other liabilities | 299,973 | 284,994 | ||||||||
1,260,410 | 1,461,087 | |||||||||
Common stock and retained earnings | 3,086,957 | 3,460,517 | ||||||||
Common stock held in treasury stock | (2,275 | ) | (3,088 | ) | ||||||
Total stockholders' equity | 3,084,682 | 3,457,429 | ||||||||
$ | 8,397,904 | $ | 8,746,780 | |||||||
RECONCILIATION OF TOTAL REVENUES AND OTHER INCOME TO TOTAL REVENUE EXCLUDING CERTAIN ITEMS, a non-GAAP measure |
(Unaudited, in thousands) | Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||
2015 | 2014 | % | 2015 | 2014 | % | ||||||||||||||||
Total revenues and other income, as reported | $ | 479,252 | $ | 616,615 | -22% | $ | 1,189,394 | $ | 1,839,481 | -35% | |||||||||||
Adjustment for certain special items: | |||||||||||||||||||||
Total change in fair value related to derivatives prior to | (64,075 | ) | (125,154 | ) | 70,593 | (84,957 | ) | ||||||||||||||
settlement | |||||||||||||||||||||
ARO settlement loss (gain) | 5 | (135 | ) | (23 | ) | 651 | |||||||||||||||
Loss (gain) on sale of assets | 681 | (167 | ) | (2,053 | ) | (281,878 | ) | ||||||||||||||
Total revenues, as adjusted, non-GAAP | $ | 415,863 | $ | 491,159 | -15% | $ | 1,257,911 | $ | 1,473,297 | -15% | |||||||||||
RANGE RESOURCES CORPORATION | ||||||||||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||||||||||||
(Unaudited, in thousands) | Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||||
Net (loss) income | $ | (300,948 | ) | $ | 146,418 | $ | (391,858 | ) | $ | 350,328 | ||||||||
Adjustments to reconcile net cash provided from continuing operations: | ||||||||||||||||||
Equity method investment, net of distributions | - | - | - | 3,096 | ||||||||||||||
Deferred income tax (benefit) expense | (134,781 | ) | 93,522 | (174,390 | ) | 230,450 | ||||||||||||
Depletion, depreciation, amortization and impairment | 656,226 | 142,450 | 955,411 | 429,484 | ||||||||||||||
Exploration dry hole costs | (19 | ) | - | 87 | 1 | |||||||||||||
Abandonment and impairment of unproved properties | 12,366 | 13,444 | 36,187 | 32,771 | ||||||||||||||
Derivative fair value (income)/loss | (202,004 | ) | (142,057 | ) | (290,052 | ) | 28,902 | |||||||||||
Cash settlements on derivative financial instruments that do not qualify for hedge accounting | 137,929 | 16,903 | 360,645 | (113,859 | ) | |||||||||||||
Allowance for bad debts | 350 | - | 600 | 250 | ||||||||||||||
Amortization of deferred issuance costs, loss on extinguishment of debt, and other | 24,482 | 1,618 | 27,572 | 31,430 | ||||||||||||||
Deferred and stock-based compensation | (30,471 | ) | (32,426 | ) | (10,679 | ) | 15,486 | |||||||||||
Loss (gain) on sale of assets and other | 681 | (167 | ) | (2,053 | ) | (281,878 | ) | |||||||||||
Changes in working capital: | ||||||||||||||||||
Accounts receivable | 5,753 | 11,823 | 79,448 | 13,098 | ||||||||||||||
Inventory and other | (3,324 | ) | 1,537 | (7,073 | ) | (5,335 | ) | |||||||||||
Accounts payable | (16,650 | ) | (33,470 | ) | (13,158 | ) | (13,355 | ) | ||||||||||
Accrued liabilities and other | (4,172 | ) | (6,180 | ) | (55,127 | ) | (65,931 | ) | ||||||||||
Net changes in working capital | (18,393 | ) | (26,290 | ) | 4,090 | (71,523 | ) | |||||||||||
Net cash provided from operating activities | $ | 145,418 | $ | 213,415 | $ | 515,560 | $ | 654,938 |
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 September 30, | Nine Months Ended September 30, | ||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
Net cash provided from operating activities, as reported | $ | 145,418 | $ | 213,415 | $ | 515,560 | $ | 654,938 | ||||||||
Net changes in working capital | 18,393 | 26,290 | (4,090 | ) | 71,523 | |||||||||||
Exploration expense | 3,566 | 10,410 | 14,888 | 36,501 | ||||||||||||
Lawsuit settlements | 1,278 | 1,252 | 2,012 | 2,203 | ||||||||||||
Legal contingency / DEP penalty | - | 4,900 | 2,500 | 4,900 | ||||||||||||
Equity method investment distribution / intercompany elimination | - | - | - | (2,819 | ) | |||||||||||
Termination costs | (76 | ) | - | 4,570 | - | |||||||||||
Non-cash compensation adjustment | 47 | 304 | 637 | 246 | ||||||||||||
Cash flow from operations before changes in working capital - a non-GAAP measure | $ | 168,626 | $ | 256,571 | $ | 536,077 | $ | 767,492 | ||||||||
ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING | ||||||||||||||||
(Unaudited, in thousands) | Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
Basic: | ||||||||||||||||
Weighted average shares outstanding | 169,362 | 168,697 | 169,142 | 165,675 | ||||||||||||
Stock held by deferred compensation plan | (2,845 | ) | (2,856 | ) | (2,815 | ) | (2,809 | ) | ||||||||
Adjusted basic | 166,517 | 165,841 | 166,327 | 162,866 | ||||||||||||
Dilutive: | ||||||||||||||||
Weighted average shares outstanding | 169,362 | 168,697 | 169,142 | 165,675 | ||||||||||||
Dilutive stock options under treasury method | (2,845 | ) | (2,237 | ) | (2,815 | ) | (1,990 | ) | ||||||||
Adjusted dilutive | 166,517 | 166,460 | 166,327 | 163,685 | ||||||||||||
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 September 30, | Nine Months Ended September 30, | ||||||||||||||
2015 | 2014 | % | 2015 | 2014 | % | |||||||||||
Natural gas, NGL and oil sales components: | ||||||||||||||||
Natural gas sales | $ | 189,113 | $ | 252,562 | $ | 589,517 | $ | 874,514 | ||||||||
NGL sales | 31,066 | 109,858 | 131,822 | 355,360 | ||||||||||||
Oil sales | 31,886 | 80,144 | 114,262 | 255,146 | ||||||||||||
Cash-settled hedges (effective): | ||||||||||||||||
Natural gas | - | 1,966 | - | 6,760 | ||||||||||||
Crude oil | - | 1,537 | - | 3,821 | ||||||||||||
Total oil and gas sales, as reported | $ | 252,065 | $ | 446,067 | -43% | $ | 835,601 | $ | 1,495,601 | -44% | ||||||
Derivative fair value income (loss), as reported: | $ | 202,004 | $ | 142,057 | $ | 290,052 | $ | (28,902) | ||||||||
Cash settlements on derivative financial instruments - (gain) loss: | ||||||||||||||||
Natural gas | (80,675) | (19,762) | (223,603) | 83,983 | ||||||||||||
NGLs | (16,047) | (1,323) | (31,608) | 13,114 | ||||||||||||
Crude Oil | (41,207) | 4,182 | (105,434) | 16,762 | ||||||||||||
Total change in fair value related to derivatives prior to settlement, a non GAAP measure | $ | 64,075 | $ | 125,154 | $ | (70,593) | $ | 84,957 | ||||||||
Transportation, gathering and compression components: | ||||||||||||||||
Natural gas | $ | 87,886 | $ | 72,186 | $ | 247,744 | $ | 205,765 | ||||||||
NGLs | 11,748 | 12,591 | 36,514 | 29,982 | ||||||||||||
Total transportation, gathering and compression, as reported | $ | 99,634 | $ | 84,777 | $ | 284,258 | $ | 235,747 | ||||||||
Natural gas, NGL and oil sales, including cash-settled derivatives: (c) | ||||||||||||||||
Natural gas sales | $ | 269,788 | $ | 274,290 | $ | 813,120 | $ | 797,291 | ||||||||
NGL sales | 47,113 | 111,181 | 163,430 | 342,246 | ||||||||||||
Oil sales | 73,093 | 77,499 | 219,696 | 242,205 | ||||||||||||
Total | $ | 389,994 | $ | 462,970 | -16% | $ | 1,196,246 | $ | 1,381,742 | -13% | ||||||
Production of oil and gas during the periods (a): | ||||||||||||||||
Natural gas (mcf) | 97,273,739 | 75,665,182 | 29% | 265,511,105 | 205,444,379 | 29% | ||||||||||
NGL (bbl) | 4,985,092 | 4,934,882 | 1% | 15,449,495 | 13,877,217 | 11% | ||||||||||
Oil (bbl) | 958,628 | 985,300 | -3% | 3,187,005 | 3,010,054 | 6% | ||||||||||
Gas equivalent (mcfe) (b) | 132,936,059 | 111,186,274 | 20% | 377,330,105 | 306,768,005 | 23% | ||||||||||
Production of oil and gas - average per day (a): | ||||||||||||||||
Natural gas (mcf) | 1,057,323 | 822,448 | 29% | 972,568 | 752,544 | 29% | ||||||||||
NGL (bbl) | 54,186 | 53,640 | 1% | 56,592 | 50,832 | 11% | ||||||||||
Oil (bbl) | 10,420 | 10,710 | -3% | 11,674 | 11,026 | 6% | ||||||||||
Gas equivalent (mcfe) (b) | 1,444,957 | 1,208,546 | 20% | 1,382,162 | 1,123,692 | 23% | ||||||||||
Average prices, including cash-settled hedges that qualify for hedge accounting before third party transportation costs: | ||||||||||||||||
Natural gas (mcf) | $ | 1.94 | $ | 3.36 | -42% | $ | 2.22 | $ | 4.29 | -48% | ||||||
NGL (bbl) | $ | 6.23 | $ | 22.26 | -72% | $ | 8.53 | $ | 25.61 | -67% | ||||||
Oil (bbl) | $ | 33.26 | $ | 82.90 | -60% | $ | 35.85 | $ | 86.03 | -58% | ||||||
Gas equivalent (mcfe) (b) | $ | 1.90 | $ | 4.01 | -53% | $ | 2.21 | $ | 4.88 | -55% | ||||||
Average prices, including cash-settled hedges and derivatives before third party transportation costs: (c) | ||||||||||||||||
Natural gas (mcf) | $ | 2.77 | $ | 3.63 | -23% | $ | 3.06 | $ | 3.88 | -21% | ||||||
NGL (bbl) | $ | 9.45 | $ | 22.53 | -58% | $ | 10.58 | $ | 24.66 | -57% | ||||||
Oil (bbl) | $ | 76.25 | $ | 78.66 | -3% | $ | 68.93 | $ | 80.47 | -14% | ||||||
Gas equivalent (mcfe) (b) | $ | 2.93 | $ | 4.16 | -30% | $ | 3.17 | $ | 4.50 | -30% | ||||||
Average prices, including cash-settled hedges and derivatives: (d) | ||||||||||||||||
Natural gas (mcf) | $ | 1.87 | $ | 2.67 | -30% | $ | 2.13 | $ | 2.88 | -26% | ||||||
NGL (bbl) | $ | 7.09 | $ | 19.98 | -64% | $ | 8.21 | $ | 22.50 | -63% | ||||||
Oil (bbl) | $ | 76.25 | $ | 78.66 | -3% | $ | 68.93 | $ | 80.47 | -14% | ||||||
Gas equivalent (mcfe) (b) | $ | 2.18 | $ | 3.40 | -36% | $ | 2.42 | $ | 3.74 | -35% | ||||||
Transportation, gathering and compression expense per mcfe | $ | 0.75 | $ | 0.76 | -2% | $ | 0.75 | $ | 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.
(c) Excluding third party transportation, gathering and compression costs.
(d) Net of transportation, gathering and compression costs.
RANGE RESOURCES CORPORATION | |||||||||||||||||||||||
RECONCILIATION OF INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AS REPORTED TO INCOME FROM OPERATIONS BEFORE INCOME TAXES EXCLUDING CERTAIN ITEMS, a non-GAAP measure |
|||||||||||||||||||||||
(Unaudited, in thousands, except per share data) | Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||
2015 | 2014 | % | 2015 | 2014 | % | ||||||||||||||||||
(Loss) income from operations before income taxes, as reported | $ | (435,729 | ) | $ | 239,940 | -282 | % | $ | (566,248 | ) | $ | 580,783 | -197 | % | |||||||||
Adjustment for certain special items: | |||||||||||||||||||||||
Loss (gain) on sale of assets | 681 | (167 | ) | (2,053 | ) | (281,878 | ) | ||||||||||||||||
Loss (gain) on ARO settlements | 5 | (135 | ) | (23 | ) | 651 | |||||||||||||||||
Change in fair value related to derivatives prior to settlement | (64,075 | ) | (125,154 | ) | 70,593 | (84,957 | ) | ||||||||||||||||
Abandonment and impairment of unproved properties | 12,366 | 13,444 | 36,187 | 32,771 | |||||||||||||||||||
Loss on early extinguishment of debt | 22,495 | - | 22,495 | 24,596 | |||||||||||||||||||
Impairment of proved property and other assets | 502,233 | - | 502,233 | 24,991 | |||||||||||||||||||
Lawsuit settlements | 1,278 | 1,252 | 2,012 | 2,203 | |||||||||||||||||||
DEP penalty | - | 4,900 | - | 4,900 | |||||||||||||||||||
Legal contingency | - | - | 2,500 | - | |||||||||||||||||||
Termination costs | (76 | ) | - | 4,570 | - | ||||||||||||||||||
Termination costs - non-cash stock-based compensation | (1 | ) | - | 1,720 | - | ||||||||||||||||||
Brokered natural gas and marketing - non-cash stock-based compensation | 618 | 656 | 1,743 | 2,314 | |||||||||||||||||||
Direct operating - non-cash stock-based compensation | 609 | 720 | 2,149 | 3,509 | |||||||||||||||||||
Exploration expenses - non-cash stock-based compensation | 688 | 1,033 | 2,171 | 3,408 | |||||||||||||||||||
General & administrative - non-cash stock-based compensation | 11,512 | 11,556 | 38,545 | 43,856 | |||||||||||||||||||
Deferred compensation plan - non-cash adjustment | (43,705 | ) | (46,198 | ) | (56,611 | ) | (37,714 | ) | |||||||||||||||
Income from operations before income taxes, as adjusted | 8,899 | 101,847 | -91 | % | 61,983 | 319,433 | -81 | % | |||||||||||||||
Income tax expense, as adjusted | |||||||||||||||||||||||
Current | - | - | - | 5 | |||||||||||||||||||
Deferred | 3,435 | 39,696 | 23,345 | 123,780 | |||||||||||||||||||
Net income excluding certain items, a non-GAAP measure | $ | 5,464 | $ | 62,151 | -91 | % | $ | 38,638 | $ | 195,648 | -80 | % | |||||||||||
Non-GAAP income per common share | |||||||||||||||||||||||
Basic | $ | 0.03 | $ | 0.37 | -92 | % | $ | 0.23 | $ | 1.20 | -81 | % | |||||||||||
Diluted | $ | 0.03 | $ | 0.37 | -92 | % | $ | 0.23 | $ | 1.20 | -81 | % | |||||||||||
Non-GAAP diluted shares outstanding, if dilutive | 166,517 | 166,460 | 166,385 | 163,685 |
RANGE RESOURCES CORPORATION | ||||
HEDGING POSITION AS OF OCTOBER 28, 2015 - | ||||
(Unaudited) | ||||
Daily Volume | Hedge Price | |||
Gas (Mmbtu) | ||||
4Q 2015 Swaps | 727,500 | $3.63 | ||
4Q 2015 Collars | 145,000 | $4.07 - $4.56 | ||
2016 Swaps | 630,000 | $3.42 | ||
2017 Swaps | 20,000 | $3.49 | ||
Oil (Bbls) | ||||
4Q 2015 Swaps | 8,750 | $98.92 | ||
2016 Swaps | 4,247 | $65.27 | ||
2017 Swaps | 500 | $55.00 | ||
C3 Propane (Bbls) | ||||
4Q 2015 Swaps | 12,000 | $0.55 | ||
2016 Swaps | 5,500 | $0.60 | ||
C4 Normal Butane (Bbls) | ||||
4Q 2015 Swaps | 3,500 | $0.72 | ||
2016 Swaps | 2,500 | $0.72 | ||
C5 Natural Gasoline (Bbls) | ||||
4Q 2015 Swaps | 4,000 | $1.16 | ||
2016 Swaps | 2,500 | $1.23 |
NOTE: SEE WEBSITE FOR OTHER SUPPLEMENTAL INFORMATION FOR THE PERIODS
Investor Contacts:
Senior Vice President
817-869-4258
rwaller@rangeresources.com
Investor Relations Manager
817-869-4266
damend@rangeresources.com
Research Manager
817-869-4267
lsando@rangeresources.com
Senior Financial Analyst
817-869-4264
mfreeman@rangeresources.com
or
Media Contact:
Director of Corporate Communications
724-873-3224
mpitzarella@rangeresources.com
www.rangeresources.com
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