Range Announces Second Quarter 2018 Financial Results
July 30, 2018 - 5:00 PM EDT
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Range Announces Second Quarter 2018 Financial Results
FORT WORTH, Texas, July 30, 2018 (GLOBE NEWSWIRE) -- RANGE RESOURCES CORPORATION (NYSE:RRC) today announced its second quarter 2018 financial results.
Highlights –
Production averaged a record 2,200 Mmcfe per day, an increase of 13% compared to second quarter 2017
Liquids production averaged 117,520 barrels per day, a 12% increase over the prior-year period, and contributed 46% of total product revenues before hedging
Natural gas differentials, including basis hedging, of $0.16 below NYMEX, a $0.23 improvement over prior-year quarter
Pre-hedge NGL realizations were $23.69 per barrel, a 63% increase over the prior-year quarter
Pre-hedge crude oil and condensate realizations of $63.07, a 45% increase over the prior-year quarter
Southwest Pennsylvania production increased 30% over the prior-year period to 1,752 Mmcfe per day
Cash from operations of $175 million, and non-GAAP cash flow of $237 million
Net loss of $80 million ($0.32 per diluted share), non-GAAP net income of $50 million ($0.20 per diluted share)
Commenting, Jeff Ventura, the Company’s CEO said, “This year is off to a solid start with another quarter of improving cash margins and record production, lifting cash flow per share by 22% over the same period last year. This effort was led by our Marcellus operations, where long laterals and the utilization of existing pads and infrastructure are a tailwind for capital efficiencies, positioning us to deliver growth within cash flow for 2018 and in our five-year outlook. At the same time, Range is intently focused on actions to fast-forward the de-levering process swiftly and prudently through asset sales. We have processes underway and believe we can execute one or more successful sales in the current year, which would improve our balance sheet and corporate returns.”
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.
Second Quarter 2018
GAAP revenues for second quarter 2018 totaled $656 million (a 3% decrease compared to second quarter 2017), GAAP net cash provided from operating activities, including changes in working capital, was $175 million, compared to $185 million in second quarter 2017, and GAAP earnings was a loss of $80 million ($0.32 per diluted share) versus earnings of $70 million ($0.28 per diluted share) in the prior-year quarter. Second quarter earnings results include a $103 million derivative loss due to increases in future commodity prices compared to a $111 million derivative gain in the prior year and a $6.6 million mark to market loss related to the deferred compensation plan compared to a $14.5 million gain in the prior year. Second quarter 2018 also included a $55 million unproved impairment primarily related to expiring leases in North Louisiana and a $15 million impairment of proved properties related to legacy assets in northwest Pennsylvania.
Non-GAAP revenues for second quarter 2018 totaled $745 million, an increase of 32% compared to second quarter 2017, and cash flow from operations before changes in working capital, a non-GAAP measure, was $237 million, compared to $194 million in second quarter 2017. Adjusted net income comparable to analysts’ estimates, a non-GAAP measure, was $50 million ($0.20 per diluted share) in second quarter 2018, compared to $16 million ($0.06 per diluted share) in the prior-year quarter, an increase of 233%.
The following table details Range’s average production and realized pricing for the second quarter 2018:
Net Production
Natural Gas (Mmcf/d)
Oil (Bbl/d)
NGLs (Bbl/d)
Natural Gas Equivalent (Mcfe/d)
1,495
13,301
104,219
2,200
Realized Pricing
Natural Gas ($/Mcf)
Oil ($/Bbl)
NGLs ($/Bbl)
Natural Gas Equivalent ($/Mcfe)
Average NYMEX price
$2.80
$67.89
Differential, including basis hedging
(0.16)
(4.82)
Realized prices before NYMEX hedges
2.64
63.07
$23.69
$3.30
Settled NYMEX hedges
0.14
(10.12)
(2.12)
(0.07)
Average realized prices after hedges
$2.78
$52.95
$21.57
$3.23
Second quarter 2018 natural gas, NGLs and oil price realizations (including the impact of cash-settled hedges and derivative settlements which correspond to analysts’ estimates) averaged $3.23 per mcfe, a 12% increase from the prior-year quarter. Additional detail on commodity price realizations can be found in the Supplemental Tables provided on the Company’s website.
The average Company natural gas price including the impact of basis hedging was $2.64 per mcf (or $0.16 per mcf below NYMEX) during the second quarter, which was significantly better than the $0.39 negative differential to NYMEX in the prior year quarter. The combination of increased pipeline connectivity, seasonally low storage levels and compressed basis across the Appalachian and Midwest regions has also improved the Company’s expected 2018 natural gas differential to NYMEX minus $0.10 per mcf.
Pre-hedge NGL realizations were $23.69 per barrel, or 35% of WTI, in second quarter 2018. Realized NGL price was above the mid-point of guidance as a result of NGL component price improvements late in the quarter. Range expects similar pricing strength through the second half of 2018, putting Range at the high-end of previously announced calendar 2018 guidance.
Crude oil and condensate price realizations, before realized hedges, for the second quarter averaged $63.07 per barrel, or $4.82 below WTI, a 45% improvement in realized price over the prior year quarter.
Unit Costs
The following table details Range’s unit costs per mcfe, excluding stock-based compensation:
Expenses
2Q 2018 ($/Mcfe)
2Q 2017 ($/Mcfe)
Increase (Decrease)
Direct operating
$
0.17
$
0.17
—
Transportation, gathering, processing and compression
1.35(a)
1.08
25%
Production and ad valorem taxes
0.05
0.06
(17%)
General and administrative
0.20
0.21
(5%)
Interest expense
0.26
0.26
—
Total cash unit costs(b)
2.03
1.78
14%
Depletion, depreciation and amortization (DD&A)
0.80
0.86
(7%)
Total unit costs plus DD&A(b)
$
2.83
$
2.65
7%
(a) Second quarter 2018 transportation, gathering, processing and compression expense reflects the change in accounting method made earlier this year. As a result of adopting the new accounting standard, expenses increased by approximately $0.21 per mcfe in second quarter 2018. There was an equal increase to NGL revenue as there is zero net impact to cash flow as a result of the change in accounting method. See page 8 in Range’s second quarter 2018 Form 10-Q. (b) May not add due to rounding
Capital Expenditures
Second quarter 2018 drilling expenditures of $260 million funded the drilling and completion of 30 (27.3 net) wells. A 100% success rate was achieved. In addition $10.3 million was spent on acreage purchases during the second quarter. Total capital expenditures year to date were $521 million. Range remains on target with its $941 million total capital budget for 2018 which is expected to be funded within cash flows, excluding asset sale proceeds.
In addition, subsequent to quarter-end, Range sold Midcontinent properties for $23 million, consisting of approximately 11 Mmcfe per day of production and expected annualized cash flow of approximately $3 million.
Operational Discussion
Range’s net production for second quarter 2018 averaged 2,200 Mmcfe per day, consisting of 1,495 Mmcf per day of natural gas, 104,219 barrels per day of NGLs and 13,301 barrels per day of condensate and oil. This makes Range one of the top 10 natural gas producers in the U.S. and a top three NGL producer amongst E&P companies, providing leverage to improving oil and NGL pricing fundamentals.
The table below summarizes wells turned to sales and the estimated activity for the remainder of the year. Estimated well costs, lateral lengths and EUR’s by area can be found in the company presentation on Range’s website.
Wells TIL 1Q 2018
Wells TIL 2Q 2018
Calendar 2018 Planned TIL
Remaining 2H 2018
SW PA Super-Rich
2
3
15
10
SW PA Wet
7
8
42
27
SW PA Dry
—
28
43
15
Total Appalachia
9
39
100
52
Total N. LA.
4
4
11
3
Total
13
43
111
55
Appalachia Division
Production for second quarter 2018 averaged approximately 1,876 net Mmcfe per day from the Appalachia division, a 25% increase over the prior-year quarter. The southwest area of the division averaged 1,752 net Mmcfe per day during the quarter, a 30% increase over second quarter 2017. This was achieved through continued operational improvements and exceptional well results across Range’s acreage position. The northeast Marcellus properties averaged 107 net Mmcf per day and legacy acreage produced approximately 17 net Mmcf per day during the second quarter 2018.
North Louisiana
Production for the division in second quarter of 2018 averaged approximately 313 net Mmcfe per day. The division brought on line four wells during the quarter, and expects to bring on line an additional three wells during the remainder of the year for a total of 11 wells in 2018.
Marketing and Transportation
Range’s marketing efforts were affected by two separate third-party midstream events during the second quarter that took away the primary method of transportation for certain production. The Company minimized the impact to cash flow by working with our various midstream and processing partners to maintain production during the downtime.
The transportation of natural gas liquids on Sunoco’s Mariner East 1 pipeline was suspended for almost two months during the second quarter. As a result, Range lost access to capacity on the Mariner East 1 pipeline for a combined 40,000 barrels per day of ethane and propane. As one of the largest NGL producers in the United States, Range has taken a portfolio approach to the sale of its purity products. The marketing team utilized alternate markets for Mariner East ethane volumes or simply sold the ethane as natural gas. For propane, Range has access to another local pipeline and railcars that continued to provide outlets to international markets via the Marcus Hook terminal as well as various domestic markets. As a result, Range was able to realize propane prices that were, on average, above the Mont Belvieu index price, while paying slightly higher transportation expense. The Mariner East 1 pipeline was returned to service in mid-June.
In early June, TransCanada’s Leach Xpress project on which Range holds natural gas capacity (300,000 Dth/day) was taken offline following a pipeline rupture in West Virginia. Range rerouted the natural gas production earmarked for the Leach Xpress capacity into local Appalachian markets. On July 15th, the Leach Xpress project returned to service.
Energy Transfer’s Rover project (phase 2), which is the last major natural gas transportation project for which Range has contracted capacity, is expected to reach full completion in third quarter 2018. Once the Rover project is in service, over 70% of Range’s production can be sold in the Gulf Coast market, which currently receives near NYMEX pricing.
Guidance – 2018
Production per day Guidance
Production for the third quarter of 2018 is expected to be approximately 2,220 Mmcfe per day. This excludes all Midcontinent volumes following the sale of that asset in early July.
Production expectations for the full year 2018 remain approximately 11% year-over-year growth.
3Q 2018 Expense Guidance
Direct operating expense:
$0.17 − $0.19 per mcfe
Transportation, gathering, processing and compression expense:
$1.38 − $1.42 per mcfe
Production tax expense:
$0.05 − $0.07 per mcfe
Exploration expense:
$7.0 − $10.0 million
Unproved property impairment expense:
$8.0 − $10.0 million
G&A expense:
$0.20 − $0.22 per mcfe
Interest expense:
$0.26 − $0.28 per mcfe
DD&A expense:
$0.80 − $0.84 per mcfe
Net brokered gas marketing expense:
~$3.0 million
3Q 2018 Natural Gas Price Differentials (including basis hedging): NYMEX minus $0.20
Based on current market indications, Range expects to average the following pre-hedge differentials for calendar 2018 production.
New Guidance
Prior Guidance
Natural Gas:
NYMEX minus $0.10
NYMEX minus $0.15
Natural Gas Liquids (including ethane):
35% − 36% of WTI
32% − 36% of WTI
Oil/Condensate:
WTI minus $5.00 to $6.00
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 more flexible financial position. Range currently has over 80% of its expected second half 2018 natural gas production hedged at a weighted average floor price of $2.97 per Mmbtu. Similarly, Range has hedged over 70% of its second half 2018 projected crude oil production at a floor price of $53.20 and over 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 to limit volatility between NYMEX and regional prices. The fair value of the basis hedges was a loss of $1.9 million as of June 30, 2018. The Company also has propane basis swap contracts which lock in the differential between Mont Belvieu and international propane indices. The fair value of these contracts was a loss of $2.1 million on June 30, 2018.
Conference Call Information
A conference call to review the financial results is scheduled on Tuesday, July 31 at 9:00 a.m. ET. To participate in the call, please dial 866-900-7525 and provide conference code 9999543 about 10 minutes prior to the scheduled start time.
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 August 31, 2018.
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). The Company provides additional comparative information on prior periods along with non-GAAP revenue disclosures on its website.
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 line in the statement of operations 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 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.
We believe that the presentation of PV-10 is relevant and useful to our investors as supplemental disclosure to the standardized measure, or after-tax amount, because it presents the discounted future net cash flows attributable to our proved reserves before taking into account future corporate income taxes and our current tax structure. While the standardized measure is dependent on the unique tax situation of each company, PV-10 is based on prices and discount factors that are consistent for all companies. Because of this, PV-10 can be used within the industry and by creditors and security analysts to evaluate estimated net cash flows from proved reserves on a more comparable basis.
RANGE RESOURCES CORPORATION (NYSE:RRC) is a leading U.S. independent oil and natural gas producer with operations focused in stacked-pay projects in the Appalachian Basin and North Louisiana. 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.
Included within this news release are certain “forward-looking statements” within the meaning of the federal securities laws, including the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 that are not limited to historical facts, but reflect Range’s current beliefs, expectations or intentions regarding future events. Words such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “outlook,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” and similar expressions are intended to identify such forward-looking statements.
All statements, except for statements of historical fact, made within regarding activities, events or developments the Company expects, believes or anticipates will or may occur in the future, such as those regarding 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 Securities and Exchange Commission (SEC), including its most recent Annual Report on Form 10-K. Unless required by law, Range undertakes no obligation to publicly update or revise any forward-looking statements to reflect circumstances or events after the date they are made.
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 its probable and possible reserves in its filings with the SEC. Range uses certain broader terms such as "resource potential,” “unrisked resource potential,” "unproved resource potential" or "upside" or other descriptions of volumes of resources potentially recoverable through additional drilling or recovery techniques that may include probable and possible reserves as defined by the SEC's guidelines. Range has not attempted to distinguish probable and possible reserves from these broader classifications. The SEC’s rules prohibit us from including in filings with the SEC these broader classifications of reserves. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of actually being realized. Unproved resource potential refers to Range's internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques and have not been reviewed by independent engineers. Unproved resource potential does not constitute reserves within the meaning of the Society of Petroleum Engineer's Petroleum Resource Management System and does not include proved reserves. Area wide unproven resource potential has not been fully risked by Range's management. “EUR”, or estimated ultimate recovery, refers to our management’s estimates of hydrocarbon quantities that may be recovered from a well completed as a producer in the area. These quantities may not necessarily constitute or represent reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or the SEC’s oil and natural gas disclosure rules. Actual quantities that may be recovered from Range's interests could differ substantially. Factors affecting ultimate recovery include the scope of Range's drilling program, which will be directly affected by the availability of capital, drilling and production costs, commodity prices, availability of drilling 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.
Interest expense – amortization of deferred financing costs
1,725
1,794
3,577
3,572
Depletion, depreciation and amortization
161,026
152,504
323,292
302,325
Impairment of proved properties and other assets
15,302
—
22,614
—
Gain on sale of assets
(156
)
(807
)
(179
)
(23,407
)
Total costs and expenses
764,538
545,910
-40
%
1,415,223
1,040,059
36
%
(Loss) income before income taxes
(108,354
)
127,201
-185
%
(16,440
)
409,707
-104
%
Income tax (benefit) expense:
Current
—
—
—
—
Deferred
(28,518
)
57,651
14,158
170,046
(28,518
)
57,651
14,158
170,046
Net (loss) income
$
(79,836
)
$
69,550
-215
%
$
(30,598
)
$
239,661
-113
%
Net (Loss) Income Per Common Share:
Basic
$
(0.32
)
$
0.28
$
(0.13
)
$
0.97
Diluted
$
(0.32
)
$
0.28
$
(0.13
)
$
0.97
Weighted average common shares outstanding, as reported:
Basic
245,880
245,177
0
%
245,795
244,916
0
%
Diluted
245,880
245,335
0
%
245,795
245,242
0
%
(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)
June 30,
December 31,
2018
2017
(Unaudited)
(Audited)
Assets
Current assets
$
384,872
$
370,627
Derivative assets
3,295
58,880
Goodwill
1,641,197
1,641,197
Natural gas and oil properties, successful efforts method
9,705,122
9,566,737
Transportation and field assets
13,190
14,666
Other
78,401
76,734
$
11,826,077
$
11,728,841
Liabilities and Stockholders’ Equity
Current liabilities
$
632,354
$
704,913
Asset retirement obligations
6,327
6,327
Derivative liabilities
101,328
44,233
Bank debt
1,304,584
1,208,467
Senior notes
2,853,948
2,851,754
Senior subordinated notes
48,630
48,585
Total debt
4,207,162
4,108,806
Deferred tax liability
707,563
693,356
Derivative liabilities
10,088
9,789
Deferred compensation liability
87,087
101,102
Asset retirement obligations and other liabilities
310,133
286,043
Common stock and retained earnings
5,765,633
5,776,203
Other comprehensive loss
(1,194
)
(1,332
)
Common stock held in treasury stock
(404
)
(599
)
Total stockholders’ equity
5,764,035
5,774,272
$
11,826,077
$
11,728,841
RECONCILIATION OF TOTAL REVENUES AND OTHER INCOME TO TOTAL REVENUE EXCLUDING CERTAIN ITEMS, a non-GAAP measure
(Unaudited, in thousands)
Three Months Ended June 30,
Six Months Ended June 30,
2018
2017
%
2018
2017
%
Total revenues and other income, as reported
$
656,184
$
673,111
-3
%
$
1,398,783
$
1,449,766
-4
%
Adjustment for certain special items:
Total change in fair value related to derivatives prior to settlement (gain) loss
89,015
(107,809
)
111,949
(277,547
)
ARO settlement (gain) loss
12
40
12
40
Total revenues, as adjusted, non-GAAP
$
745,211
$
565,342
32
%
$
1,510,744
$
1,172,259
29
%
RANGE RESOURCES CORPORATION
CASH FLOWS FROM OPERATING ACTIVITIES
(Unaudited in thousands)
Three Months Ended June 30,
Six Months Ended June 30,
2018
2017
2018
2017
Net (loss) income
$
(79,836
)
$
69,550
$
(30,598
)
$
239,661
Adjustments to reconcile net cash provided from continuing operations:
Deferred income tax (benefit) expense
(28,518
)
57,651
14,158
170,046
Depletion, depreciation, amortization and impairment
176,328
152,504
345,906
302,325
Exploration dry hole costs
—
161
2
161
Abandonment and impairment of unproved properties
54,922
5,193
66,695
9,613
Derivative fair value loss (income)
103,290
(111,195
)
117,299
(276,752
)
Cash settlements on derivative financial instruments that do not qualify for hedge accounting
(14,275
)
3,387
(5,350
)
(794
)
Allowance for bad debts
(1,500
)
300
(1,500
)
300
Amortization of deferred issuance costs, loss on extinguishment of debt, and other
1,064
1,247
2,376
2,557
Deferred and stock-based compensation
15,640
990
34,167
1,952
(Gain) loss on sale of assets and other
(156
)
(807
)
(179
)
(23,407
)
Changes in working capital:
Accounts receivable
(68,338
)
(8,920
)
(14,425
)
(13,610
)
Inventory and other
6,090
848
796
3,716
Accounts payable
(32,838
)
(5,958
)
14,615
18,426
Accrued liabilities and other
43,070
20,515
1,553
(22,866
)
Net changes in working capital
(52,016
)
6,485
2,539
(14,334
)
Net cash provided from operating activities
$
174,943
$
185,466
$
545,515
$
411,328
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 June 30,
Six Months Ended June 30,
2018
2017
2018
2017
Net cash provided from operating activities, as reported
$
174,943
$
185,466
$
545,515
$
411,328
Net changes in working capital
52,016
(6,485
)
(2,539
)
14,334
Exploration expense
7,128
13,809
14,094
21,806
Lawsuit settlements
1,155
540
1,332
1,163
Termination costs
—
(50
)
—
2,400
Non-cash compensation adjustment
1,685
801
1,802
1,092
Cash flow from operations before changes in working capital – non-GAAP measure
$
236,927
$
194,081
$
560,204
$
452,123
ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING
(Unaudited, in thousands)
Three Months Ended June 30,
Six Months Ended June 30,
2018
2017
2018
2017
Basic:
Weighted average shares outstanding
249,324
247,852
248,952
247,622
Stock held by deferred compensation plan
(3,444
)
(2,675
)
(3,157
)
(2,706
)
Adjusted basic
245,880
245,177
245,795
244,916
Dilutive:
Weighted average shares outstanding
249,324
247,852
248,952
247,622
Dilutive stock options under treasury method
(3,444
)
(2,517
)
(3,157
)
(2,380
)
Adjusted dilutive
245,880
245,335
245,795
245,242
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 June 30,
Six Months Ended June 30,
2018
2017
%
2018
2017
%
Natural gas, NGL and oil sales components:
Natural gas sales
$
360,351
$
336,534
$
791,924
$
707,866
NGL sales
224,703
123,784
427,230
261,847
Oil sales
76,336
45,819
138,865
95,854
Total oil and gas sales, as reported
$
661,390
$
506,137
31
%
$
1,358,019
$
1,065,567
27
%
Derivative fair value income (loss), as reported:
$
(103,290
)
$
111,195
$
(117,299
)
$
276,752
Cash settlements on derivative financial instruments – (gain) loss:
Natural gas
(18,113
)
(942
)
(50,621
)
(8,397
)
NGLs
20,144
3,131
35,412
17,464
Crude Oil
12,244
(5,575
)
20,559
(8,272
)
Total change in fair value related to derivatives prior to settlement, a non-GAAP measure
$
(89,015
)
$
107,809
$
(111,949
)
$
277,547
Transportation, gathering, processing and compression components:
Natural gas
$
164,064
$
129,557
$
321,298
$
251,750
NGLs
105,846
62,033
193,240
117,488
Total transportation, gathering, processing and compression, as reported
$
269,910
$
191,590
$
514,538
$
369,238
Natural gas, NGL and oil sales, including cash-settled derivatives: (c)
Natural gas sales
$
378,464
$
337,476
$
842,545
$
716,263
NGL sales
204,559
120,653
391,818
244,383
Oil sales
64,092
51,394
118,306
104,126
Total
$
647,115
$
509,523
27
%
1,352,669
1,064,772
27
%
Production of oil and gas during the periods (a):
Natural gas (mcf)
136,057,805
119,487,827
14
%
271,011,900
235,744,164
15
%
NGL (bbl)
9,483,910
8,524,267
11
%
18,753,941
17,060,995
10
%
Oil (bbl)
1,210,379
1,052,784
15
%
2,273,813
2,118,070
7
%
Gas equivalent (mcfe) (b)
200,223,539
176,950,133
13
%
397,178,424
350,818,554
13
%
Production of oil and gas – average per day (a):
Natural gas (mcf)
1,495,141
1,313,053
14
%
1,497,303
1,302,454
15
%
NGL (bbl)
104,219
93,673
11
%
103,613
94,260
10
%
Oil (bbl)
13,301
11,569
15
%
12,563
11,702
7
%
Gas equivalent (mcfe) (b)
2,200,259
1,944,507
13
%
2,194,356
1,938,224
13
%
Average prices, excluding derivative settlements and before third party transportation costs:
Natural gas (mcf)
$
2.65
$
2.82
-6
%
$
2.92
$
3.00
-3
%
NGL (bbl)
$
23.69
$
14.52
63
%
$
22.78
$
15.35
48
%
Oil (bbl)
$
63.07
$
43.52
45
%
$
61.07
$
45.26
35
%
Gas equivalent (mcfe) (b)
$
3.30
$
2.86
15
%
$
3.42
$
3.04
13
%
Average prices, including derivative settlements before third party transportation costs: (c)
Natural gas (mcf)
$
2.78
$
2.82
-2
%
$
3.11
$
3.04
2
%
NGL (bbl)
$
21.57
$
14.15
52
%
$
20.89
$
14.32
46
%
Oil (bbl)
$
52.95
$
48.82
8
%
$
52.03
$
49.16
6
%
Gas equivalent (mcfe) (b)
$
3.23
$
2.88
12
%
$
3.41
$
3.04
12
%
Average prices, including derivative settlements and after third party transportation costs: (d)
Natural gas (mcf)
$
1.58
$
1.74
-9
%
$
1.92
$
1.97
-2
%
NGL (bbl)
$
10.41
$
6.88
51
%
$
10.59
$
7.44
42
%
Oil (bbl)
$
52.95
$
48.82
8
%
$
52.03
$
49.16
6
%
Gas equivalent (mcfe) (b)
$
1.88
$
1.80
5
%
$
2.11
$
1.98
6
%
Transportation, gathering and compression expense per mcfe
$
1.35
$
1.08
25
%
$
1.30
$
1.05
23
%
(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.
RANGE RESOURCES CORPORATION
RECONCILIATION OF INCOME (LOSS) 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 June 30,
Six Months Ended June 30,
2018
2017
%
2018
2017
%
(Loss) income from operations before income taxes, as reported
$
(108,354
)
$
127,201
185
%
$
(16,440
)
$
409,707
104
%
Adjustment for certain special items:
(Gain) loss on sale of assets
(156
)
(807
)
(179
)
(23,407
)
Loss (gain) on ARO settlements
12
40
12
40
Change in fair value related to derivatives prior to settlement
General & administrative – non-cash stock-based compensation
8,814
14,279
32,725
25,197
Deferred compensation plan – non-cash adjustment
6,615
(14,466
)
(782
)
(27,635
)
Income before income taxes, as adjusted
68,548
25,513
169
%
220,739
123,959
78
%
Income tax expense, as adjusted
Current
—
—
—
—
Deferred (a)
18,231
9,622
57,748
47,250
Net income excluding certain items, a non-GAAP measure
$
50,317
$
15,891
217
%
$
162,991
$
76,709
112
%
Non-GAAP income per common share
Basic
$
0.20
$
0.06
233
%
$
0.66
$
0.31
113
%
Diluted
$
0.20
$
0.06
233
%
$
0.66
$
0.31
113
%
Non-GAAP diluted shares outstanding, if dilutive
246,692
245,335
246,530
245,242
(a) Deferred taxes for 2017 to be approximately 38% and 26% for 2018.
RANGE RESOURCES CORPORATION
RECONCILIATION OF NET (LOSS) INCOME, EXCLUDING CERTAIN ITEMS AND ADJUSTMENT EARNINGS PER SHARE, non-GAAP measures
(In thousands, except per share data)
Three Months Ended June 30,
Six Months Ended June 30,
2018
2017
2018
2017
Net (loss) income, as reported
$
(79,836
)
$
69,550
$
(30,598
)
$
239,661
Adjustment for certain special items:
(Gain) loss on sale of assets
(156
)
(807
)
(179
)
(23,407
)
Loss (gain) on ARO settlements
12
40
12
40
Change in fair value related to derivatives prior to settlement
89,015
(107,809
)
111,949
(277,547
)
Impairment of proved property
15,302
—
22,614
—
Abandonment and impairment of unproved properties
54,922
5,193
66,695
9,613
Lawsuit settlements
1,155
540
1,332
1,163
Termination costs
—
(50
)
(37
)
2,400
Non-cash stock-based compensation
10,037
15,671
35,575
29,625
Deferred compensation plan
6,615
(14,466
)
(782
)
(27,635
)
Tax impact
(46,749
)
48,029
(43,590
)
122,796
Net income (loss) excluding certain items, a non-GAAP measure
$
50,317
$
15,891
$
162,991
$
76,709
Net (loss) income per diluted share, as reported
$
(0.32
)
$
0.28
$
(0.13
)
$
0.97
Adjustment for certain special items per diluted share:
(Gain) loss on sale of assets
(0.00
)
(0.00
)
(0.00
)
(0.10
)
Change in fair value related to derivatives prior to settlement
0.36
(0.44
)
0.46
(1.13
)
Impairment of proved property
0.06
—
0.09
—
Abandonment and impairment of unproved properties
0.22
0.02
0.27
0.04
Lawsuit settlements
0.00
0.00
0.01
0.00
Termination costs
—
(0.00
)
(0.00
)
0.01
Non-cash stock-based compensation
0.04
0.06
0.14
0.12
Deferred compensation plan
0.03
(0.06
)
(0.00
)
(0.11
)
Adjustment for rounding differences
—
—
—
0.01
Tax impact
(0.19
)
0.20
(0.18
)
0.50
Net income (loss) per diluted share, excluding certain items, a non-GAAP measure
$
0.20
$
0.06
$
0.66
$
0.31
Adjusted earnings (loss) per share, a non-GAAP measure:
Basic
$
0.20
$
0.06
$
0.66
$
0.31
Diluted
$
0.20
$
0.06
$
0.66
$
0.31
RANGE RESOURCES CORPORATION
RECONCILIATION OF CASH MARGIN PER MCFE, a non-GAAP measure
(Unaudited, in thousands, except per unit data)
Three Months Ended June 30,
Six Months Ended June 30,
2018
2017
2018
2017
Revenues
Natural gas, NGL and oil sales, as reported
$
661,390
$
506,137
$
1,358,019
$
1,065,587
Derivative fair value income (loss), as reported
(103,290
)
111,195
(117,299
)
276,752
Less non-cash fair value (gain) loss
89,015
(107,809
)
111,949
(277,547
)
Brokered natural gas and marketing and other, as reported
98,084
55,779
158,063
107,427
Less ARO settlement and other (gains) losses
(176
)
237
(400
)
170
Cash revenue applicable to production
745,023
565,539
1,510,332
1,172,389
Expenses
Direct operating, as reported
35,088
31,420
73,210
59,443
Less direct operating stock-based compensation
(539
)
(522
)
(1,130
)
(1,046
)
Transportation, gathering and compression, as reported
269,910
191,590
514,538
369,238
Production and ad valorem taxes, as reported
10,140
9,969
20,066
19,132
Brokered natural gas and marketing, as reported
102,747
55,857
158,341
109,407
Less brokered natural gas and marketing stock-based compensation
(313
)
(388
)
(598
)
(651
)
General and administrative, as reported
47,583
52,322
116,000
99,818
Less G&A stock-based compensation
(8,814
)
(14,279
)
(32,725
)
(25,197
)
Less lawsuit settlements
(1,155
)
(540
)
(1,332
)
(1,163
)
Interest expense, as reported
53,862
47,926
106,247
95,027
Less amortization of deferred financing costs
(1,725
)
(1,794
)
(3,577
)
(3,572
)
Cash expenses
506,784
371,561
949,040
720,436
Cash margin, a non-GAAP measure
$
238,239
$
193,978
$
561,292
$
451,953
Mmcfe produced during period
200,223
176,950
397,178
350,818
Cash margin per mcfe
$
1.19
$
1.10
$
1.41
$
1.29
RECONCILIATION OF (LOSS) INCOME BEFORE INCOME TAXES TO CASH MARGIN
(Unaudited, in thousands, except per unit data)
Three Months Ended June 30,
Six Months Ended June 30,
2018
2017
2018
2017
(Loss) income before income taxes, as reported
$
(108,354
)
$
127,201
$
(16,440
)
$
409,707
Adjustments to reconcile (loss) income before income taxes to cash margin:
ARO settlements and other (gains) losses
(176
)
237
(400
)
170
Derivative fair value (income) loss
103,290
(111,195
)
117,299
(276,752
)
Net cash receipts on derivative settlements
(14,275
)
3,386
(5,350
)
(795
)
Exploration expense
7,128
13,970
14,096
21,967
Lawsuit settlements
1,155
540
1,332
1,163
Termination costs
—
(50
)
(37
)
2,400
Deferred compensation plan
6,615
(14,466
)
(782
)
(27,635
)
Stock-based compensation (direct operating, brokered natural gas and marketing, general and administrative and termination costs)
10,037
15,671
35,575
29,625
Interest – amortization of deferred financing costs
1,725
1,794
3,577
3,572
Depletion, depreciation and amortization
161,026
152,504
323,292
302,325
(Gain) loss on sale of assets
(156
)
(807
)
(179
)
(23,407
)
Impairment of proved property and other assets
15,302
—
22,614
—
Abandonment and impairment of unproved properties
54,922
5,193
66,695
9,613
Cash margin, a non-GAAP measure
$
238,239
$
193,978
$
561,292
$
451,953
RANGE RESOURCES CORPORATION
HEDGING POSITION AS OF July 20, 2018 – (Unaudited)
Daily Volume
Hedge Price
Gas 1
3Q 2018 Swaps
1,346,848 Mmbtu
$2.98
4Q 2018 Swaps
1,373,261 Mmbtu
$2.97
4Q 2018 Sold Calls
70,000 Mmbtu
$3.10 2
2019 Swaps
832,534 Mmbtu
$2.83
2020 Swaps
10,000 Mmbtu
$2.75
Oil
3Q 2018 Swaps
8,500 bbls
$53.20
4Q 2018 Swaps
8,500 bbls
$53.20
2019 Swaps
6,624 bbls
$54.57
1H 2020 Swaps
1,125 bbls
$57.67
C2 Ethane
3Q 2018 Swaps
1,337 bbls
$0.315/gallon
C3 Propane 3
3Q 2018 Swaps
12,168 bbls
$0.69/gallon
4Q 2018 Swaps
10,668 bbls
$0.67/gallon
4Q 2018 Collars
1,250 bbls
$0.90 x $1.00/gallon
1Q 2019 Swaps
1,500 bbls
$0.90/gallon
C4 Normal Butane
3Q 2018 Swaps
4,250 bbls
$0.81/gallon
4Q 2018 Swaps
4,250 bbls
$0.81/gallon
C5 Natural Gasoline
3Q 2018 Swaps
5,152 bbls
$1.22/gallon
4Q 2018 Swaps
5,152 bbls
$1.23/gallon
2019 Swaps
1,244 bbls
$1.30/gallon
(1) Range also sold call swaptions of 380,000 Mmbtu/d for calendar 2019, and 140,000 Mmbtu/d for calendar 2020 at average strike prices of $2.96 and $2.81 per Mmbtu, respectively (2) Sold Calls have an average deferred Premium of +$0.16 per Mmbtu (3) Swaps incorporate international propane hedges
SEE WEBSITE FOR OTHER SUPPLEMENTAL INFORMATION FOR THE PERIODS AND ADDITIONAL HEDGING DETAILS
