rrc-8k_20171024.htm

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 8-K

 

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

Date of report (Date of earliest event reported):

October 24, 2017 (October 24, 2017)

 

RANGE RESOURCES CORPORATION

(Exact name of registrant as specified in its charter)

 

 

Delaware

 

001-12209

 

34-1312571

(State or other jurisdiction of
incorporation)

 

(Commission
File Number)

 

(IRS Employer
Identification No.)

 

 

 

 

 

 

100 Throckmorton, Suite 1200

Ft. Worth, Texas

 

76102

(Address of principal executive offices)

 

(Zip Code)

Registrant’s telephone number, including area code:  (817) 870-2601

(Former name or former address, if changed since last report):  Not applicable

 

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligations of the registrant under any of the following provisions (see General Instruction A.2. below):

 

Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

 

 

 

 

Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

 

 

 

 

Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

 

 

 

 

Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).

Emerging Growth Company

    

  

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

    

 

 

 


ITEM 2.02 Results of Operations and Financial Condition

On October 24, 2017 Range Resources Corporation issued a press release announcing its third quarter 2017 results. A copy of this press release is being furnished as an exhibit to this report on Form 8-K.

ITEM 9.01 Financial Statements and Exhibits

(d) Exhibits:

99.1 Press Release dated October 24, 2017

 


SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

 

RANGE RESOURCES CORPORATION

 

By:   

/s/ Roger S. Manny

 

Roger S. Manny

 

Chief Financial Officer

Date:  October 24, 2017

 

rrc-ex991_33.htm

Exhibit 99.1

NEWS RELEASE

RANGE ANNOUNCES THIRD QUARTER 2017 RESULTS

FORT WORTH, TEXAS, OCTOBER 24, 2017…RANGE RESOURCES CORPORATION (NYSE: RRC) today announced its third quarter 2017 financial results.  

Highlights –

 

Year to date 2017 GAAP net income was $112 million, or $0.45 per diluted share, compared to a net loss of $361 million, or $2.10 per share in the comparable period of 2016

 

Year to date net cash provided from operating activities (GAAP) was $601 million, compared to $206 million in the comparable period of 2016, an improvement of 192% while year to date cash flow from operations before changes in working capital, (non-GAAP), reached $656 million, compared to $316 million, an improvement of 108%

 

Two recently completed Marcellus super-rich pads were brought on line with average per well 24-hour IPs of 41.3 Mmcfe per day, containing 64% liquids, with 20% being condensate  

 

Record third quarter production totaled 1.99 Bcfe per day, an increase of 32% compared to the prior-year quarter

 

Third quarter NGL pre-hedge realized prices improved to $16.93 per barrel versus $11.17 per barrel in the prior-year quarter, a 52% improvement

 

Third quarter natural gas price differential including the impact of basis hedges improved to minus ($0.51) per mcf, compared to minus ($0.68) in the prior-year quarter, a 25% improvement

 

Third quarter crude oil and condensate realized prices improved to $4.80 per barrel below WTI versus $5.81 per barrel below WTI in the prior-year quarter, a 17% improvement

Commenting, Jeff Ventura, the Company’s CEO said, “This is an exciting time for Range as we are nearing an inflection point in our Marcellus development and as we continue to improve well results in North Louisiana.  In the Marcellus, the last of our natural gas transportation projects are coming on line over the next few months which will allow us to develop our Marcellus position over the long-term while having access to better priced markets.  This buildout process has been years in the making and we believe Range’s combination of high-quality assets and infrastructure provide a solid foundation to deliver strong returns for many years.”

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.  “Cash margin” as used in this release represents cash revenues related to production less cash expenses related to production, which are comprised of expense categories included in “unit costs” excluding depletion, depreciation and amortization, but including brokered natural gas and marketing. “Cash margin per mcfe” represents cash margin 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.



Third Quarter 2017

GAAP revenues for the third quarter of 2017 totaled $482 million, a 17% increase over the prior-year quarter. GAAP net cash provided from operating activities including changes in working capital was $189 million versus $33 million in third quarter 2016 and a GAAP net loss of $128 million ($0.52 per diluted share) versus a loss of $42 million ($0.23 per diluted share) in the prior-year quarter. Third quarter 2017 included $88 million in derivative losses due to increased commodity prices, compared to a $65 million gain in third quarter 2016.  Third quarter 2017 also included $43 million in unproved property impairment compared to $6 million in third quarter 2016, as a result of increasing lease expirations due to budgeting constraints, primarily in North Louisiana. Proved property impairment of $64 million was recorded in third quarter 2017 on properties located in Oklahoma and the Texas Panhandle.

Non-GAAP revenues for third quarter 2017 totaled $587 million, a 46% increase compared to third quarter 2016 and cash flow from operations before changes in working capital, a non-GAAP measure, reached $204 million, compared to $123 million in third quarter 2016. Adjusted net income comparable to analysts’ estimates, a non-GAAP measure, was $12 million ($0.05 per diluted share) compared to a loss of $10 million ($0.06 per diluted share) for third quarter 2016.  

The Company’s total unit costs were $2.66 per mcfe, 1% lower than third quarter 2016, while cash unit costs were $1.78 per mcfe, 2% higher than the prior-year quarter. General and administrative, interest and depletion, depreciation and amortization expenses per mcfe continued to trend lower.  Transportation, gathering, processing and compression expense increased by $0.05 per mcfe over the prior-year quarter, which was more than offset by higher realized prices, as products were moved to more favorable markets with higher prices, thereby resulting in increased cash margins from the previous year. Direct operating costs increased by $0.04 per mcfe over the prior-year quarter due to higher workover and well service costs.  Production, and ad valorem taxes increased by $0.02 per mcfe due to a one-time production tax adjustment.  

Expenses

 

3Q 2017

(per mcfe)

 

3Q 2016

(per mcfe)

 

 

Increase

(Decrease)

 

 

 

 

 

 

 

 

Direct operating

 

$  0.20

 

$  0.16

 

 

25%

Transportation, gathering, processing and compression

 

    1.05

 

    1.00

 

 

5%

Production and ad valorem taxes

 

    0.07

 

    0.05

 

 

40%

General and administrative

 

    0.20

 

    0.21

 

 

(5%)

Interest expense

 

    0.27

 

    0.33

 

 

(18%)

Total cash unit costs(a)

 

    1.78

 

    1.75

 

 

2%

Depletion, depreciation and amortization

 

    0.87

 

    0.95

 

 

(8%)

Total unit costs(a)

 

$  2.66

 

$  2.70

 

 

(1%)

 

 

 

 

 

 

 

 

(a) Totals may not add due to rounding.

 

 

 

 

 

 

 

Third quarter 2017 natural gas, NGLs and oil price realizations (including the impact of cash-settled hedges and derivative settlements which correspond to analysts’ estimates) averaged $2.78 per mcfe, a 27% increase from the prior-year quarter as price differentials improved for all of the Company’s products.  Additional detail on commodity price realizations can be found in the Supplemental Tables provided on the Company’s website.

 

Production and realized prices by each commodity for third quarter 2017 were:  natural gas – 1,322 Mmcf per day ($2.48 per mcf), NGLs – 96,661 barrels per day ($16.93 per barrel) and crude oil and condensate – 14,003 barrels per day ($43.34 per barrel).

 

The average Company natural gas price differential including the impact of basis hedges for third quarter 2017 improved to minus ($0.51) per mcf, compared to minus ($0.68) in third quarter 2016.  The third quarter 2017 average natural gas price, before all hedging settlements, was $2.48 per mcf as compared to $2.11 per mcf in the prior-year quarter.

2


 

Pre-hedge NGL realizations improved to 35% of West Texas Intermediate (“WTI”) crude oil in third quarter 2017, compared to 25% of WTI in third quarter 2016.  Total NGL pricing per barrel before realized cash-settled hedging improved to $16.93 for third quarter 2017 compared to $11.17 per barrel in the prior-year quarter.  Range’s realized NGL pricing includes ethane extraction and is net of processing and certain other costs.  On a gross basis, without processing fees, Range's Marcellus C3+ NGL barrel for the third quarter was approximately 69% of WTI.  

 

Crude oil and condensate price realizations, before realized hedges, for the third quarter 2017 improved to $43.34, or $4.80 per barrel below WTI, compared to $39.15, or $5.81 per barrel below WTI in the prior-year quarter.  

Cash Margins

Third quarter cash margins improved to $1.09 per mcfe compared to $0.82 per mcfe in third quarter 2016, an improvement of 33%.  Year to date cash margins improved to $1.21 per mcfe, versus $0.77 per mcfe in the comparable period of 2016, an improvement of 57%.  See the attached table that reconciles income (loss) before income taxes with cash margins, a non-GAAP measure.

Capital Expenditures

Third quarter 2017 drilling expenditures of $305 million funded the drilling and completion of 35 (33 net) wells.  A 97% success rate was achieved.  In addition, during the quarter, $7.8 million was incurred on acreage purchases, $3.5 million on gas gathering systems and $5.1 million on seismic expense.  Range is on target with its $1.15 billion capital budget for 2017.

Financial Position and Liquidity

At September 30, 2017, Range had total debt outstanding of $4.0 billion, before amortization of debt issuance costs and premium, consisting of $2.9 billion in senior notes, $1.1 billion in bank debt and $49 million in senior subordinated notes.  The outstanding bank debt of $1.1 billion combined with $286 million of undrawn letters of credit provides committed liquidity of $628 million.


3


Operational Discussion

Range has updated its investor presentation. Please see www.rangeresources.com under the Investors tab, “Company Presentations” area, for the presentation entitled, “Company Presentation – October 24, 2017”.

The table below summarizes quarterly activity and the number of wells expected to be turned in line (TIL) for the remainder of 2017 and total year of 2017:

 

 

2017


 

Wells TIL —

1st and 2nd

Quarters

Wells TIL —

3rd Quarter

Wells to be

TIL —

4th Quarter

Planned Annual

Total Wells

to Sales

Super-Rich Area

 

14

11

7

32

Wet Area

 

15

10

15

40

Dry- SW

 

14

1

24

39

Dry- NE

 

2

2

Total Marcellus

 

45

22

46

113

 

 

 

 

 

 

Upper Red

 

22

3

9

34

Lower Red

 

8

5

13

Pink

 

3

3

6

Extension Area

 

1

2

3

Total N. LA.

 

33

7

16

56

 

 

 

 

 

 

Company Total

 

78

29

62

169

 

 

 

 

 

 

Appalachia Division

Division production for third quarter 2017 averaged 1.60 net Bcfe per day, a 15% increase over the prior-year quarter.  The southwest properties averaged 1.45 net Bcfe per day during the quarter, an 18% increase over the prior-year quarter.  The northeast properties averaged 153 net Mmcf per day during the quarter, a 9% decrease over the prior-year quarter.  The division brought on line 22 wells in the third quarter, 11 in the super-rich area, 10 in the wet area, and one in the southwest dry area.  As shown in the table above, the number of wells brought on line will increase in the fourth quarter when prices are expected to improve and new pipeline infrastructure becomes available.

The division continues to drill longer laterals, thereby improving capital efficiency by lowering well costs per foot and increasing recoveries.  Lateral lengths in the third quarter averaged over 11,700 feet compared to an average lateral length of less than 6,171 feet in third quarter 2016.  Average lateral lengths of 10,000 feet or greater is the expectation for 2018 as the Company’s goal of holding acreage and capturing resource potential is essentially complete and the focus is now on maximizing operational efficiencies and improving returns.  The combination of longer laterals and additional completion efficiencies has allowed Range to lower total well costs on a normalized basis by 25%, as compared to the previous year.

Two recent four well pads were completed in the super-rich area with seven wells turned to sales in the third quarter.  Both pads are examples of impressive liquids production in addition to gas.  One pad had an average 24-hour IP per well of 41.7 Mmcfe per day consisting of 16.2 Mmcf of gas, 1,089 barrels of condensate and 3,172 barrels of NGLs.  The wells were completed with an average lateral length of 9,478 feet with 48 stages.  The other pad had an average 24-hour IP of 40.6 Mmcfe per day consisting of 12.7 Mmcf of gas, 1,755 barrels of condensate and 2,904 barrels of NGLs.  The wells were completed with an average lateral length of 9,880 feet with 50 stages.

 


4


North Louisiana Division

Production for the division in the third quarter of 2017 averaged 360 net Mmcfe per day.  The division brought seven wells on line during the quarter.  The last three wells were previously disclosed at an energy conference in September, as they represent the first wells Range has operated from start to finish.  The three wells continue to perform well, with the two Upper Red wells having 30 day rates to sales of 25.8 and 20.7 Mmcfe per day, with lateral lengths of 7,427 feet and 6,827 feet.  A Lower Deep Pink well on the same pad averaged 20.2 Mmcfe per day to sales for 30 days.  It appears to be the best Pink interval well drilled in the field to date.

Activity in the extension area to the south of Terryville is continuing, building upon the encouraging results previously announced.  A well was recently completed in a new fault block south of Terryville and north of Driscoll field.  Early production data is promising, with production rates over 3.5 Mmcf per day per 1,000 feet of lateral.  Two offset horizontal wells to the east and west of Vernon field are planned with one well currently drilling.

The division expects to bring on line 16 wells in the fourth quarter.

Marketing and Transportation

During the next two quarters, several incremental natural gas transportation projects in southwest Appalachia are expected to commence operations.  Once in service, Range’s natural gas transportation portfolio will be largely complete, allowing Marcellus natural gas volumes to be directed toward expanding markets, especially the Gulf Coast where significant incremental natural gas demand is expected over the next several years.  

TransCanada’s Rayne/Leach Xpress project and Enbridge’s TETCO Adair Southwest project are both expected to be in service before the end of 2017, and Energy Transfer’s Rover Phase 2 project is expected to be available in early 2018.  In combination, these projects will add an additional 900,000 Mmbtu per day to Range’s gross capacity and are expected to improve corporate natural gas differentials to NYMEX minus $0.15 or better during 2018.  As a result of these additional transportation commitments, Range is expecting its transportation, gathering, compression and processing expense to increase to ~$1.20 per Mcfe when all three projects are fully in service before trending back down as capacity is fully utilized.

Range is also well-positioned to benefit from the improving NGL macro environment.  The Company reported NGL pre-hedge pricing improved to 35% of WTI in the third quarter, compared to 25% of WTI a year ago.  This substantial improvement in NGL pricing realizations was led by propane, which achieved multi-year highs in September.  As the only producer with propane capacity on Mariner East 1, Range has been able to capture above Mont Belvieu prices by exporting the majority of its propane to international markets since early 2016.  As a result of Range’s projects currently in place, and improving NGL market fundamentals, Range expects fourth quarter 2017 pre-hedge NGL differentials to be approximately 35% of WTI. Based on current strip prices, Range anticipates pre-hedge NGL realizations of 30% to 32% of WTI in 2018.


5


Guidance – 2017

2017 Production per day Guidance

Range’s fourth quarter production is expected to be 2,170 Mmcfe per day.  This results in annual production growth of 30%, or organic growth of approximately 10%.

4Q 2017 Expense Guidance

 Direct operating expense:

 $0.18 — $0.20 per mcfe

 Transportation, gathering, processing and compression expense:

 $1.05 — $1.07 per mcfe

 Production tax expense:

 $0.06 — $0.07 per mcfe

 Exploration expense:

 $15.0 — $17.0 million

 Unproved property impairment expense:

 $22.0 — $24.0 million

 G&A expense:

 $0.21 — $0.23 per mcfe

 Interest expense:

 $0.27 — $0.29 per mcfe

 DD&A expense:

 $0.86 — $0.88 per mcfe

 Net brokered gas marketing expense:

 ~$3.0 million

Price Differentials

Based on current market pricing indications, Range expects to receive the following pre-hedge differentials for its production in the full year of 2017 and 2018.

 

 2017

 2018

 

 

 

 Natural Gas:

 NYMEX minus $0.30

 NYMEX minus $0.15 or better

 Natural Gas Liquids (with ethane):

 32% of WTI

 30% — 32% 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 strong, flexible financial position. Range currently has over 75% of its expected remaining 2017 natural gas production hedged at a weighted average floor price of approximately $3.24 per mcf, and over 50% of 2018 production hedged at approximately $3.14.  Similarly, Range has hedged approximately 70% of its remaining 2017 projected crude oil production at a floor price of approximately $56.00 and approximately 70% 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 basis differentials to limit volatility between NYMEX and regional prices, primarily in the Appalachian region.  The fair value of the basis hedges as of September 30, 2017 was a loss of $4.7 million. Range also hedges propane prices with swap contracts that lock in the differential between Mont Belvieu and international propane indices.  The fair value of these contracts was a gain of $1.1 million on September 30, 2017.

Conference Call Information

A conference call to review the financial results is scheduled on Wednesday, October 25 at 9:00 a.m. ET. To participate in the call, please dial 866-900-7525 and provide conference code 95985702 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 November 25, 2017.


6


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.

Cash margin as used in this release represents cash revenues related to production less cash expenses related to production as shown in the table below. Cash margin per mcfe represents cash margin divided by production, and is similar to a unit based gross profit calculation as used in other industries, which can be useful in comparing a measure of gross profitability between time periods.  A reconciliation is provided in the table between cash margin and the related GAAP measure of income (loss) before income taxes.  On its website, the Company provides additional comparative information on prior periods for cash flow, non-GAAP earnings and cash margin 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 statement of operations.  The Company believes that it is important to furnish a table reflecting the details of the various components of each statement of operations 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 Statement of Operations to better inform the reader of the details of each amount, the changes between periods and the effect on its financial results.


7


RANGE RESOURCES CORPORATION (NYSE: RRC) is a leading U.S. independent natural gas, NGL and oil 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.

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 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), which are incorporated by reference.  Range undertakes no obligation to publicly update or revise any forward-looking statements.

The SEC permits oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions as well as the option to disclose probable and possible reserves.  Range has elected not to disclose the Company’s probable and possible reserves in its filings with the SEC.  Range uses certain broader terms such as "resource potential,” “unrisked resource potential,” "unproved resource potential" or "upside" or other descriptions of volumes of resources potentially recoverable through additional drilling or recovery techniques that may include probable and possible reserves as defined by the SEC's guidelines.  Range has not attempted to distinguish probable and possible reserves from these broader classifications. The SEC’s rules prohibit us from including in filings with the SEC these broader classifications of reserves.  These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of actually being realized.  Unproved resource potential refers to Range's internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques and have not been reviewed by independent engineers.  Unproved resource potential does not constitute reserves within the meaning of the Society of Petroleum Engineer's Petroleum Resource Management System and does not include proved reserves.  Area wide unproven resource potential has not been fully risked by Range's management.  “EUR”, or estimated ultimate recovery, refers to our management’s estimates of hydrocarbon quantities that may be recovered from a well completed as a producer in the area. These quantities may not necessarily constitute or represent reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or the SEC’s oil and natural gas disclosure rules. Actual quantities that may be recovered from Range's interests could differ substantially.  Factors affecting ultimate recovery include the scope of Range's drilling program, which will be directly affected by the availability of capital, drilling and production costs, commodity prices, availability of drilling 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.

8


 

2017-07

SOURCE:   Range Resources Corporation

Investor Contacts:

Laith Sando, Vice President – Investor Relations

817-869-4267

lsando@rangeresources.com

David Amend, Investor Relations Manager

817-869-4266

damend@rangeresources.com

Michael Freeman, Senior Financial Analyst

817-869-4264

mfreeman@rangeresources.com

Josh Stevens, Financial Analyst

817-869-1564

jrstevens@rangeresources.com

Media Contact:

Michael Mackin, Director of External Affairs

724-743-6776

mmackin@rangeresources.com

www.rangeresources.com


9


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,

 

 

 

2017

 

 

 

2016

 

 

 

%

 

 

 

2017

 

 

 

2016

 

 

 

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues and other income:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas, NGLs and oil sales (a)

$

507,541

 

 

$

304,477

 

 

 

 

 

 

$

1,573,128

 

 

$

738,570

 

 

 

 

 

Derivative fair value (loss)/income

 

(88,426

)

 

 

64,556

 

 

 

 

 

 

 

188,326

 

 

 

(11,334

)

 

 

 

 

Brokered natural gas, marketing and other (b)

 

61,145

 

 

 

44,114

 

 

 

 

 

 

 

168,742

 

 

 

118,445

 

 

 

 

 

ARO settlement gain (loss) (b)

 

104

 

 

 

(6

)

 

 

 

 

 

 

64

 

 

 

(14

)

 

 

 

 

Other (b)

 

1,868

 

 

 

66

 

 

 

 

 

 

 

1,738

 

 

 

750

 

 

 

 

 

Total revenues and other income

 

482,232

 

 

 

413,207

 

 

 

17

%

 

 

1,931,998

 

 

 

846,417

 

 

 

128

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Direct operating

 

36,371

 

 

 

21,890

 

 

 

 

 

 

 

94,768

 

 

 

65,331

 

 

 

 

 

Direct operating – non-cash stock-based compensation (c)

 

517

 

 

 

497

 

 

 

 

 

 

 

1,563

 

 

 

1,781

 

 

 

 

 

Transportation, gathering, processing and compression  

 

191,645

 

 

 

138,764

 

 

 

 

 

 

 

560,883

 

 

 

400,871

 

 

 

 

 

Production and ad valorem taxes  

 

11,993

 

 

 

6,717

 

 

 

 

 

 

 

31,125

 

 

 

18,653

 

 

 

 

 

Brokered natural gas and marketing

 

59,384

 

 

 

44,167

 

 

 

 

 

 

 

168,140

 

 

 

120,756

 

 

 

 

 

Brokered natural gas and marketing — non-cash
stock-based compensation (c)

 

389

 

 

 

455

 

 

 

 

 

 

 

1,040

 

 

 

1,349

 

 

 

 

 

Exploration

 

22,206

 

 

 

6,335

 

 

 

 

 

 

 

44,173

 

 

 

16,972

 

 

 

 

 

Exploration – non-cash stock-based compensation (c)  

 

561

 

 

 

608

 

 

 

 

 

 

 

1,596

 

 

 

1,669

 

 

 

 

 

Abandonment and impairment of unproved properties  

 

42,568

 

 

 

6,082

 

 

 

 

 

 

 

52,181

 

 

 

23,769

 

 

 

 

 

General and administrative  

 

36,461

 

 

 

29,428

 

 

 

 

 

 

 

109,619

 

 

 

87,819

 

 

 

 

 

General and administrative — non-cash stock-based
compensation (c)

 

9,959

 

 

 

11,126

 

 

 

 

 

 

 

35,156

 

 

 

37,682

 

 

 

 

 

General and administrative — lawsuit settlements

 

5,865

 

 

 

120

 

 

 

 

 

 

 

7,028

 

 

 

1,444

 

 

 

 

 

General and administrative — bad debt expense  

 

750

 

 

 

350

 

 

 

 

 

 

 

1,050

 

 

 

800

 

 

 

 

 

Memorial merger expenses

 

 

 

 

33,791

 

 

 

 

 

 

 

 

 

 

36,412

 

 

 

 

 

Termination costs

 

(16

)

 

 

136

 

 

 

 

 

 

 

2,384

 

 

 

303

 

 

 

 

 

Termination costs — non-cash stock-based compensation (c)

 

(31

)

 

 

 

 

 

 

 

 

 

1,665

 

 

 

 

 

 

 

 

Deferred compensation plan (d)

 

(9,203

)

 

 

(11,636

)

 

 

 

 

 

 

(36,838

)

 

 

30,166

 

 

 

 

 

Interest expense

 

49,179

 

 

 

45,967

 

 

 

 

 

 

 

144,206

 

 

 

121,464

 

 

 

 

 

Depletion, depreciation and amortization  

 

159,749

 

 

 

131,489

 

 

 

 

 

 

 

462,074

 

 

 

374,440

 

 

 

 

 

Impairment of proved properties and other assets

 

63,679

 

 

 

 

 

 

 

 

 

 

63,679

 

 

 

43,040

 

 

 

 

 

(Gain) loss on sale of assets

 

(102

)

 

 

2,597

 

 

 

 

 

 

 

(23,509

)

 

 

7,544

 

 

 

 

 

Total costs and expenses

 

681,924

 

 

 

468,883

 

 

 

45

%

 

 

1,721,983

 

 

 

1,392,265

 

 

 

24

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Loss) income before income taxes

 

(199,692

)

 

 

(55,676

)

 

 

-259

%

 

 

210,015

 

 

 

(545,848

)

 

 

138

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income tax (benefit) expense:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred

 

(71,992

)

 

 

(13,705

)

 

 

 

 

 

 

98,054

 

 

 

(185,169

)

 

 

 

 

 

 

(71,992

)

 

 

(13,705

)

 

 

 

 

 

 

98,054

 

 

 

(185,169

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net (loss) income

$

(127,700

)

 

$

(41,971

)

 

 

-204

%

 

$

111,961

 

 

$

(360,679

)

 

 

131

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net (loss) income Per Common Share:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

$

(0.52

)

 

$

(0.23

)

 

 

 

 

 

$

0.45

 

 

$

(2.10

)

 

 

 

 

Diluted

$

(0.52

)

 

$

(0.23

)

 

 

 

 

 

$

0.45

 

 

$

(2.10

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted average common shares outstanding, as reported:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

245,244

 

 

 

180,683

 

 

 

36

%

 

 

245,027

 

 

 

171,571

 

 

 

43

%

Diluted

 

245,244

 

 

 

180,683

 

 

 

36

%

 

 

245,280

 

 

 

171,571

 

 

 

43

%

(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.


10


RANGE RESOURCES CORPORATION

BALANCE SHEETS

 

 

 

 

 

 

 

(In thousands)

 

September 30,

 

 

 

December 31,

 

 

 

2017

 

 

 

2016

 

 

 

(Unaudited)

 

 

 

(Audited)

 

Assets

 

 

 

 

 

 

 

Current assets

$

307,074

 

 

$

268,605

 

Derivative assets

 

30,688

 

 

 

13,483

 

Goodwill

 

1,641,197

 

 

 

1,654,292

 

Natural gas and oil properties, successful efforts method

 

9,568,776

 

 

 

9,256,337

 

Transportation and field assets

 

15,604

 

 

 

16,873

 

Other

 

74,400

 

 

 

72,655

 

 

$

11,637,739

 

 

$

11,282,245

 

 

 

 

 

 

 

 

 

Liabilities and Stockholders’ Equity

 

 

 

 

 

 

 

Current liabilities

$

631,562

 

 

$

530,373

 

Asset retirement obligations

 

7,271

 

 

 

7,271

 

Derivative liabilities

 

32,533

 

 

 

165,009

 

 

 

 

 

 

 

 

 

Bank debt

 

1,082,708

 

 

 

876,428

 

Senior notes

 

2,850,692

 

 

 

2,848,591

 

Senior subordinated notes

 

48,562

 

 

 

48,498

 

Total debt

 

3,981,962

 

 

 

3,773,517

 

 

 

 

 

 

 

 

 

Deferred tax liability

 

1,042,889

 

 

 

943,343

 

Derivative liabilities

 

16,292

 

 

 

24,491

 

Deferred compensation liability

 

91,014

 

 

 

119,231

 

Asset retirement obligations and other liabilities

 

296,736

 

 

 

310,642

 

 

 

 

 

 

 

 

 

Common stock and retained earnings

 

5,538,079

 

 

 

5,409,577

 

Common stock held in treasury stock

 

(599

)

 

 

(1,209

)

Total stockholders’ equity

 

5,537,480

 

 

 

5,408,368

 

 

$

11,637,739

 

 

$

11,282,245

 

 

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,

 

 

 

2017

 

 

 

2016

 

 

 

%

 

 

 

2017

 

 

 

2016

 

 

 

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total revenues and other income, as reported

$

482,232

 

 

$

413,207

 

 

 

17

%

 

$

1,931,998

 

 

$

846,417

 

 

 

128

%

Adjustment for certain special items:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total change in fair value related to derivatives
prior to settlement (gain) loss

 

105,283

 

 

 

(11,443

)

 

 

 

 

 

 

(172,264

)

 

 

271,991

 

 

 

 

 

ARO settlement (gain) loss

 

(104

)

 

 

6

 

 

 

 

 

 

 

(64

)

 

 

14

 

 

 

 

 

Total revenues, as adjusted, non-GAAP

$

587,411

 

 

$

401,770

 

 

 

46

%

 

$

1,759,670

 

 

$

1,118,422

 

 

 

57

%

 


11


RANGE RESOURCES CORPORATION

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Unaudited in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended September 30,

 

 

Nine Months Ended September 30,

 

 

 

2017

 

 

 

2016

 

 

 

2017

 

 

 

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net (loss) income

$

(127,700

)

 

$

(41,971

)

 

$

111,961

 

 

$

(360,679

)

Adjustments to reconcile net cash provided from continuing operations:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred income tax (benefit) expense

 

(71,992

)

 

 

(13,705

)

 

 

98,054

 

 

 

(185,169

)

Depletion, depreciation, amortization and impairment

 

223,428

 

 

 

131,489

 

 

 

525,753

 

 

 

417,480

 

Exploration dry hole costs

 

9,005

 

 

 

2

 

 

 

9,166

 

 

 

2

 

Abandonment and impairment of unproved properties

 

42,568

 

 

 

6,082

 

 

 

52,181

 

 

 

23,769

 

Derivative fair value loss (income)

 

88,426

 

 

 

(64,556

)

 

 

(188,326

)

 

 

11,334

 

Cash settlements on derivative financial instruments

 

16,856

 

 

 

53,113

 

 

 

16,062

 

 

 

260,657

 

Allowance for bad debts

 

750

 

 

 

350

 

 

 

1,050

 

 

 

800

 

Amortization of deferred issuance costs, loss on extinguishment of debt, and other

 

1,627

 

 

 

1,946

 

 

 

4,184

 

 

 

5,383

 

Deferred and stock-based compensation

 

1,985

 

 

 

971

 

 

 

3,937

 

 

 

72,689

 

(Gain) loss on sale of assets and other

 

(102

)

 

 

2,597

 

 

 

(23,509

)

 

 

7,544

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Changes in working capital:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accounts receivable

 

(26,084

)

 

 

(9,970

)

 

 

(39,694

)

 

 

31,985

 

Inventory and other

 

(5,220

)

 

 

(11,276

)

 

 

(1,504

)

 

 

(776

)

Accounts payable

 

26,289

 

 

 

(22,074

)

 

 

44,715

 

 

 

(41,268

)

Accrued liabilities and other

 

9,368

 

 

 

(362

)

 

 

(13,498

)

 

 

(37,914

)

Net changes in working capital

 

4,353

 

 

 

(43,682

)

 

 

(9,981

)

 

 

(47,973

)

Net cash provided from operating activities

$

189,204

 

 

$

32,636

 

 

$

600,532

 

 

$

205,837

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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,

 

 

 

2017

 

 

 

2016

 

 

 

2017

 

 

 

2016

 

Net cash provided from operating activities, as reported

$

189,204

 

 

$

32,636

 

 

$

600,532

 

 

$

205,837

 

Net changes in working capital

 

(4,353

)

 

 

43,682

 

 

 

9,981

 

 

 

47,973

 

Exploration expense

 

13,200

 

 

 

6,333

 

 

 

35,006

 

 

 

16,970

 

Memorial merger expenses

 

 

 

 

33,791

 

 

 

 

 

 

36,412

 

Lawsuit settlements

 

5,865

 

 

 

120

 

 

 

7,028

 

 

 

1,444

 

Cash paid to exchange senior subordinated notes

 

 

 

 

6,600

 

 

 

 

 

 

6,600

 

Termination costs

 

(16

)

 

 

136

 

 

 

2,384

 

 

 

303

 

Non-cash compensation adjustment

 

291

 

 

 

(79

)

 

 

1,383

 

 

 

(37

)

Cash flow from operations before changes in working capital — non-GAAP measure

$

204,191

 

 

$

123,219

 

 

$

656,314

 

 

$

315,502

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Unaudited, in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended September 30,

 

 

Nine Months Ended September 30,

 

 

 

2017

 

 

 

2016

 

 

 

2017

 

 

 

2016

 

Basic:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted average shares outstanding

 

248,133

 

 

 

183,491

 

 

 

247,794

 

 

 

174,361

 

Stock held by deferred compensation plan

 

(2,889

)

 

 

(2,808

)

 

 

(2,767

)

 

 

(2,790

)

Adjusted basic

 

245,244

 

 

 

180,683

 

 

 

245,027

 

 

 

171,571

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Dilutive:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted average shares outstanding

 

248,133

 

 

 

183,491

 

 

 

247,794

 

 

 

174,361

 

Dilutive stock options under treasury method

 

(2,889

)

 

 

(2,808

)

 

 

(2,514

)

 

 

(2,790

)

Adjusted dilutive

 

245,244

 

 

 

180,683

 

 

 

245,280

 

 

 

171,571

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 


12


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,

 

 

 

2017

 

 

 

2016

 

 

 

%

 

 

 

2017

 

 

 

2016

 

 

 

%

 

Natural gas, NGL and oil sales components:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas sales

$

301,114

 

 

$

197,476

 

 

 

 

 

 

$

1,009,000

 

 

$

464,098

 

 

 

 

 

NGL sales

 

150,593

 

 

 

75,259

 

 

 

 

 

 

 

412,440

 

 

 

198,877

 

 

 

 

 

Oil sales

 

55,834

 

 

 

31,742

 

 

 

 

 

 

 

151,688

 

 

 

75,595

 

 

 

 

 

Total oil and gas sales, as reported

$

507,541

 

 

$

304,477

 

 

 

67

%

 

$

1,573,128

 

 

$

738,570

 

 

 

113

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative fair value income (loss), as reported:

$

(88,426

)

 

$

64,556

 

 

 

 

 

 

$

188,326

 

 

$

(11,334

)

 

 

 

 

Cash settlements on derivative financial instruments – (gain) loss:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas

 

(26,250

)

 

 

(35,822

)

 

 

 

 

 

 

(34,647

)

 

 

(205,985

)

 

 

 

 

NGLs

 

15,995

 

 

 

(8,514

)

 

 

 

 

 

 

33,459

 

 

 

(25,395

)

 

 

 

 

Crude Oil

 

(6,602

)

 

 

(8,777

)

 

 

 

 

 

 

(14,874

)

 

 

(29,277

)

 

 

 

 

Total change in fair value related to derivatives prior to settlement, a
non-GAAP measure

$

(105,283

)

 

$

11,443

 

 

 

 

 

 

$

172,264

 

 

$

(271,991

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Transportation, gathering, processing and compression components:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas

$

133,019

 

 

$

99,465

 

 

 

 

 

 

$

384,769

 

 

$

288,355

 

 

 

 

 

NGLs

 

58,626

 

 

 

39,299

 

 

 

 

 

 

 

176,114

 

 

 

112,516

 

 

 

 

 

Total transportation, gathering, processing and compression, as reported

$

191,645

 

 

$

138,764

 

 

 

 

 

 

$

560,883

 

 

$

400,871

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas, NGL and oil sales, including cash-settled derivatives: (c)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas sales

$

327,364

 

 

$

233,298

 

 

 

 

 

 

$

1,043,647

 

 

$

670,083

 

 

 

 

 

NGL sales

 

134,598

 

 

 

83,773

 

 

 

 

 

 

 

378,981

 

 

 

224,272

 

 

 

 

 

Oil sales

 

62,436

 

 

 

40,519

 

 

 

 

 

 

 

166,562

 

 

 

104,872

 

 

 

 

 

Total

$

524,398

 

 

$

357,590

 

 

 

47

%

 

 

1,589,190

 

 

 

999,227

 

 

 

59

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production of oil and gas during the periods (a):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (mcf)

 

121,644,949

 

 

 

93,466,385

 

 

 

30

%

 

 

357,389,113

 

 

 

261,331,126

 

 

 

37

%

NGL (bbl)

 

8,892,778

 

 

 

6,739,161

 

 

 

32

%

 

 

25,953,773

 

 

 

19,579,843

 

 

 

33

%

Oil (bbl)

 

1,288,303

 

 

 

810,878

 

 

 

59

%

 

 

3,406,373

 

 

 

2,504,757

 

 

 

36

%

Gas equivalent (mcfe) (b)

 

182,731,435

 

 

 

138,766,619

 

 

 

32

%

 

 

533,549,989

 

 

 

393,838,726

 

 

 

35

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production of oil and gas – average per day (a):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (mcf)

 

1,322,228

 

 

 

1,015,939

 

 

 

30

%

 

 

1,309,118

 

 

 

953,763

 

 

 

37

%

NGL (bbl)

 

96,661

 

 

 

73,252

 

 

 

32

%

 

 

95,069

 

 

 

71,459

 

 

 

33

%

Oil (bbl)

 

14,003

 

 

 

8,814

 

 

 

59

%

 

 

12,478

 

 

 

9,141

 

 

 

36

%

Gas equivalent (mcfe) (b)  

 

1,986,211

 

 

 

1,508,333

 

 

 

32

%

 

 

1,954,396

 

 

 

1,437,368

 

 

 

36

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average prices, including cash-settled hedges before third party transportation costs:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (mcf)

$

2.48

 

 

$

2.11

 

 

 

17

%

 

$

2.82

 

 

$

1.78

 

 

 

59

%

NGL (bbl)

$

16.93

 

 

$

11.17

 

 

 

52

%

 

$

15.89

 

 

$

10.16

 

 

 

56

%

Oil (bbl)

$

43.34

 

 

$

39.15

 

 

 

11

%

 

$

44.53

 

 

$

30.18

 

 

 

48

%

Gas equivalent (mcfe) (b)

$

2.78

 

 

$

2.19

 

 

 

27

%

 

$

2.95

 

 

$

1.88

 

 

 

57

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average prices, including cash-settled hedges and derivatives
before third party transportation costs: (c)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (mcf)

$

2.69

 

 

$

2.50

 

 

 

8

%

 

$

2.92

 

 

$

2.56

 

 

 

14

%

NGL (bbl)

$

15.14

 

 

$

12.43

 

 

 

22

%

 

$

14.60

 

 

$

11.45

 

 

 

27

%

Oil (bbl)

$

48.46

 

 

$

49.97

 

 

 

-3

%

 

$

48.90

 

 

$

41.87

 

 

 

17

%

Gas equivalent (mcfe) (b)

$

2.87

 

 

$

2.58

 

 

 

11

%

 

$

2.98

 

 

$

2.54

 

 

 

17

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average prices, including cash-settled hedges and derivatives: (d)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (mcf)

$

1.60

 

 

$

1.43

 

 

 

12

%

 

$

1.84

 

 

$

1.46

 

 

 

26

%

NGL (bbl)

$

8.54

 

 

$

6.60

 

 

 

29

%

 

$

7.82

 

 

$

5.71

 

 

 

37

%

Oil (bbl)

$

48.46

 

 

$

49.97

 

 

 

-3

%

 

$

48.90

 

 

$

41.87

 

 

 

17

%

Gas equivalent (mcfe) (b)

$

1.82

 

 

$

1.58

 

 

 

15

%

 

$

1.93

 

 

$

1.52

 

 

 

27

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Transportation, gathering and compression expense per mcfe

$

1.05

 

 

$

1.00

 

 

 

5

%

 

$

1.05

 

 

$

1.02

 

 

 

3

%

(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.

13


RANGE RESOURCES CORPORATION

RECONCILIATION OF NET INCOME (LOSS),

AND ADJUSTED EARNINGS PER SHARE EXCLUDING

CERTAIN ITEMS, a non-GAAP measure

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(In thousands, except per share data)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

September 30,

 

 

 

Nine Months Ended

September 30,

 

 

 

 

2017

 

 

 

2016

 

 

 

 

2017

 

 

 

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net (loss) income, as reported

 

$

(127,700

)

 

$

(41,971

)

 

 

$

111,961

 

 

$

(360,679

)

 

Adjustment for certain special items:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Gain) loss on sale of assets

 

(102

)

 

 

2,597

 

 

 

 

(23,509

)

 

 

7,544

 

 

Loss (gain) on ARO settlements

 

(104

)

 

 

6

 

 

 

 

(64

)

 

 

14

 

 

Change in fair value related to derivatives prior to settlement

 

105,283

 

 

 

(11,443

)

 

 

 

(172,264

)

 

 

271,991

 

 

Impairment of proved property

 

63,679

 

 

 

 

 

 

 

63,679

 

 

 

43,040

 

 

Abandonment and impairment of unproved properties

 

42,568

 

 

 

6,082

 

 

 

 

52,181

 

 

 

23,769

 

 

MRD merger expenses

 

 

 

 

33,791

 

 

 

 

 

 

 

36,412

 

 

Fees paid to exchange senior subordinated notes

 

 

 

 

6,600

 

 

 

 

 

 

 

6,600

 

 

Lawsuit settlements

 

5,865

 

 

 

120

 

 

 

 

7,028

 

 

 

1,444

 

 

Termination costs

 

(16

)

 

 

136

 

 

 

 

2,384

 

 

 

303

 

 

Non-cash stock-based compensation

 

11,395

 

 

 

12,686

 

 

 

 

41,020

 

 

 

42,481

 

 

Deferred compensation plan

 

(9,203

)

 

 

(11,636

)

 

 

 

(36,838

)

 

 

30,166

 

 

Tax impact

 

(80,034

)

 

 

(7,338

)

 

 

 

42,762

 

 

 

(153,836

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) excluding certain items, a non-GAAP measure

$

11,631

 

 

$

(10,370

)

 

 

$

88,340

 

 

$

(50,751

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net (loss) income per diluted share, as reported

 

$

(0.52

)

 

$

(0.23

)

 

 

$

0.45

 

 

$

(2.10

)

 

Adjustment for certain special items per diluted share:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Gain) loss on sale of assets

 

 

 

 

0.01

 

 

 

 

(0.10

)

 

 

0.04

 

 

Change in fair value related to derivatives prior to settlement

 

0.43

 

 

 

(0.06

)

 

 

 

(0.70

)

 

 

1.59

 

 

Impairment of proved property

 

0.26

 

 

 

 

 

 

 

0.26

 

 

 

0.25

 

 

Abandonment and impairment of unproved properties

 

0.17

 

 

 

0.03

 

 

 

 

0.21

 

 

 

0.14

 

 

MRD merger expenses

 

 

 

 

0.19

 

 

 

 

 

 

 

0.21

 

 

Fees paid to exchange senior subordinated notes

 

 

 

 

0.04

 

 

 

 

 

 

 

0.04

 

 

Lawsuit settlements

 

0.02

 

 

 

 

 

 

 

0.03

 

 

 

0.01

 

 

Termination costs

 

 

 

 

 

 

 

 

0.01

 

 

 

 

 

Non-cash stock-based compensation

 

0.05

 

 

 

0.07

 

 

 

 

0.17

 

 

 

0.25

 

 

Deferred compensation plan

 

(0.04

)

 

 

(0.06

)

 

 

 

(0.15

)

 

 

0.18

 

 

Adjustment for rounding differences

 

0.01

 

 

 

(0.01

)

 

 

 

0.01

 

 

 

(0.01

)

 

Tax impact

 

(0.33

)

 

 

(0.04

)

 

 

 

0.17

 

 

 

(0.90

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) per diluted share, excluding certain items, a non-GAAP measure

$

0.05

 

 

$

(0.06

)

 

 

$

0.36

 

 

$

(0.30

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Adjusted income (loss) per share, a non-GAAP measure:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

$

0.05

 

 

$

(0.06

)

 

 

$

0.36

 

 

$

(0.30

)

 

Diluted

$

0.05

 

 

$

(0.06

)

 

 

$

0.36

 

 

$

(0.30

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 


14


RANGE RESOURCES CORPORATION

RECONCILIATION OF CASH MARGIN PER MCFE, a non-GAAP measure

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Unaudited, in thousands, except per unit data)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

September 30,

 

 

 

Nine Months Ended

September 30,

 

 

 

 

2017

 

 

 

2016

 

 

 

 

2017

 

 

 

2016

 

 

Revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas, NGL and oil sales, as reported

$

507,541

 

 

$

304,477

 

 

 

$

1,573,128

 

 

$

738,570

 

 

Derivative fair value income (loss), as reported

 

(88,426

)

 

 

64,556

 

 

 

 

188,326

 

 

 

(11,334

)

 

Less non-cash fair value (gain) loss

 

105,283

 

 

 

(11,443

)

 

 

 

(172,264

)

 

 

271,991

 

 

Brokered natural gas and marketing and other, as reported

 

63,117

 

 

 

44,174

 

 

 

 

170,544

 

 

 

119,181

 

 

Less ARO settlement and other (gains) losses

 

(1,972

)

 

 

(60

)

 

 

 

(1,802

)

 

 

(736

)

 

Cash revenue applicable to production

 

585,543

 

 

 

401,704

 

 

 

 

1,757,932

 

 

 

1,117,672

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Direct operating, as reported

 

36,888

 

 

 

22,387

 

 

 

 

96,331

 

 

 

67,112

 

 

Less direct operating stock-based compensation

 

(517

)

 

 

(497

)

 

 

 

(1,563

)

 

 

(1,781

)

 

Transportation, gathering and compression, as reported

 

191,645

 

 

 

138,764

 

 

 

 

560,883

 

 

 

400,871

 

 

Production and ad valorem taxes, as reported

 

11,993

 

 

 

6,717

 

 

 

 

31,125

 

 

 

18,653

 

 

Brokered natural gas and marketing, as reported

 

59,773

 

 

 

44,622

 

 

 

 

169,180

 

 

 

122,105

 

 

Less brokered natural gas and marketing stock-based compensation

 

(389

)

 

 

(455

)

 

 

 

(1,040

)

 

 

(1,349

)

 

General and administrative, as reported

 

53,035

 

 

 

41,024

 

 

 

 

152,853

 

 

 

127,745

 

 

Less G&A stock-based compensation

 

(9,959

)

 

 

(11,126

)

 

 

 

(35,156

)

 

 

(37,682

)

 

Less lawsuit settlements

 

(5,865

)

 

 

(120

)

 

 

 

(7,028

)

 

 

(1,444

)

 

Interest expense, as reported

 

49,179

 

 

 

45,967

 

 

 

 

144,206

 

 

 

121,464

 

 

Cash expenses

 

385,783

 

 

 

287,283

 

 

 

 

1,109,791

 

 

 

815,694

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash margin, a non-GAAP measure

$

199,760

 

 

$

114,421

 

 

 

$

648,141

 

 

$

301,978

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Mmcfe produced during period

 

182,731

 

 

 

138,767

 

 

 

 

533,550

 

 

 

393,839

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash margin per mcfe

$

1.09

 

 

$

0.82

 

 

 

$

1.21

 

 

$

0.77

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

RECONCILIATION OF INCOME (LOSS) BEFORE INCOME TAXES TO CASH MARGIN

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Unaudited, in thousands, except per unit data)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

September 30,

 

 

 

Nine Months Ended

September 30,

 

 

 

 

2017

 

 

 

2016

 

 

 

 

2017

 

 

 

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Loss) income before income taxes, as reported

$

(199,692

)

 

$

(55,676

)

 

 

$

210,015

 

 

$

(545,848

)

 

Adjustments to reconcile (loss) income before income taxes to cash margin:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

ARO settlements and other (gains) losses

 

(1,972

)

 

 

(60

)

 

 

 

(1,802

)

 

 

(736

)

 

Derivative fair value (income) loss

 

88,426

 

 

 

(64,556

)

 

 

 

(188,326

)

 

 

11,334

 

 

Net cash receipts on derivative settlements

 

16,857

 

 

 

53,113

 

 

 

 

16,062

 

 

 

260,657

 

 

Exploration expense

 

22,206

 

 

 

6,335

 

 

 

 

44,173

 

 

 

16,972

 

 

Lawsuit settlements

 

5,865

 

 

 

120

 

 

 

 

7,028

 

 

 

1,444

 

 

MRD merger expenses

 

 

 

 

33,791

 

 

 

 

 

 

 

36,412

 

 

Termination costs

 

(16

)

 

 

136

 

 

 

 

2,384

 

 

 

303

 

 

Deferred compensation plan

 

(9,203

)

 

 

(11,636

)

 

 

 

(36,838

)

 

 

30,166

 

 

Stock-based compensation (direct operating, brokered natural gas and marketing, general and administrative and termination costs)

 

11,395

 

 

 

12,686

 

 

 

 

41,020

 

 

 

42,481

 

 

Depletion, depreciation and amortization

 

159,749

 

 

 

131,489

 

 

 

 

462,074

 

 

 

374,440

 

 

(Gain) loss on sale of assets

 

(102

)

 

 

2,597

 

 

 

 

(23,509

)

 

 

7,544

 

 

Impairment of proved property and other assets

 

63,679

 

 

 

 

 

 

 

63,679

 

 

 

43,040

 

 

Abandonment and impairment of unproved properties

 

42,568

 

 

 

6,082

 

 

 

 

52,181

 

 

 

23,769

 

 

 

Cash margin, a non-GAAP measure

$

199,760

 

 

$

114,421

 

 

 

$

648,141

 

 

$

301,978

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

    

15


RANGE RESOURCES CORPORATION

HEDGING POSITION AS OF OCTOBER 23, 2017

(Unaudited) –

 

 

 

 

 

Daily Volume

 

 

 

Hedge Price

 

 

Gas  1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

4Q 2017 Swaps

 

 

 

867,935 Mmbtu

 

 

 

$3.20

 

 

1Q 2018 Swaps

 

 

 

1,020,000 Mmbtu

 

 

 

$3.43

 

 

2Q-4Q 2018 Swaps2

 

 

 

790,000 Mmbtu

 

 

 

$3.01

 

 

2019 Swaps2

 

 

 

72,329 Mmbtu

 

 

 

$3.00

 

 

 

 

 

 

 

 

 

 

 

 

 

4Q 2017 Collars

 

 

 

122,609 Mmbtu

 

 

 

$3.45 x $4.11

 

 

1Q 2018 Collars

 

 

 

60,000 Mmbtu

 

 

 

$3.40 x $3.76

 

 

 

 

 

 

 

 

 

 

 

 

 

4Q 2017 Puts

 

 

 

185,870 Mmbtu

 

 

 

$3.50 ($0.32) 3

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

4Q 2017 Swaps

 

 

 

9,511 bbls

 

 

 

$56.03

 

 

2018 Swaps

 

 

 

6,750 bbls

 

 

 

$52.89

 

 

 

 

 

 

 

 

 

 

 

 

 

2019 Swaps

 

 

 

1,000 bbls

 

 

 

$51.50

 

 

 

 

 

 

 

 

 

 

 

 

 

C2 Ethane

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

4Q 2017 Swaps

 

 

 

3,000 bbls

 

 

 

$0.27/gallon

 

 

1H 2018 Swaps

 

 

 

250 bbls

 

 

 

$0.29/gallon

 

 

 

 

 

 

 

 

 

 

 

 

 

C3 Propane 4

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

4Q 2017 Swaps

 

 

 

17,576 bbls

 

 

 

$0.60/gallon

 

 

1Q 2018 Swaps

 

 

 

12,000 bbls

 

 

 

$0.65/gallon

 

 

2Q-4Q 2018 Swaps

 

 

 

7,932 bbls

 

 

 

$0.61/gallon

 

 

 

 

 

 

 

 

 

 

 

 

 

C4 Normal Butane

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

4Q 2017 Swaps

 

 

 

9,000 bbls

 

 

 

$0.76/gallon

 

 

1Q 2018 Swaps

 

 

 

5,500 bbls

 

 

 

$0.82/gallon

 

 

2Q-4Q 2018 Swaps

 

 

 

4,250 bbls

 

 

 

$0.81/gallon

 

 

 

 

 

 

 

 

 

 

 

 

 

C5 Natural Gasoline

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

4Q 2017 Swaps

 

 

 

6,416 bbls

 

 

 

$1.08/gallon

 

 

1Q 2018 Swaps

 

 

 

5,167 bbls

 

 

 

$1.18/gallon

 

 

2Q-4Q 2018 Swaps

 

 

 

3,655 bbls

 

 

 

$1.17/gallon

 

 

(1)

Range has deferred calls at a strike of $3.75 for 4Q17. Total volume of 1,650,000 Mmbtu with a deferred premium price of $0.31 paid to Range

 

(2)

Range also sold call swaptions of 160,000 Mmbtu/d for April-December 2018 and 220,000 Mmbtu/d for calendar 2019 at average strike prices of $3.02 and $3.05 per Mmbtu, respectively

 

(3)

Notes deferred premium on puts

 

(4)

Incorporates international propane hedges

SEE WEBSITE FOR OTHER SUPPLEMENTAL INFORMATION FOR THE PERIODS AND ADDITIONAL HEDGING DETAILS

16