UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 8-K

 

CURRENT REPORT

P ursuant to Section 13 or 15( d )

of the Securities Exchange Act of 1934

Date of report (Date of earliest event reported):

February 26, 2019 (February 25, 2019)

 

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 Street, Suite 1200

Fort 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 February 25, 2019 Range Resources Corporation issued a press release announcing its 2018 results. A copy of this press release is being furnished as an exhibit to this report on Form 8-K.

ITEM 9.01 Financial Statements and Exhibits

(d) Exhibits:

99.1 Press Release dated February 25, 2019

 


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/ Mark S. Scucchi

 

Mark S. Scucchi

 

Chief Financial Officer

Date:  February 26 , 2019

 

Exhibit 99.1

NEWS RELEASE

RANGE ANNOUNCES FOURTH QUARTER AND YEAR-END 2018 RESULTS

FORT WORTH, TEXAS, FEBRUARY 25, 2019…RANGE RESOURCES CORPORATION (NYSE: RRC) today announced its fourth quarter and year-end 2018 financial results.  

 

Commenting on the results and 2019 plans, Jeff Ventura, the Company’s CEO said, “Range made solid progress on key strategic objectives in 2018.  Our capital spending was disciplined, coming in $31 million under budget due to efficient operations, longer laterals and innovative water recycling.  For the year, Range generated free cash flow, reduced absolute debt, and also made good progress on our leverage targets with contribution of the royalty sale announced in late 2018.

 

I believe the Company is positioned well, with a high-quality resource base capable of generating sustainable free cash at current strip prices.  Our economic resilience is further demonstrated in the year-end PV 10 reserve value of $9.9 billion using futures strip pricing from year-end, which equates to approximately $24 per share, net of debt. Going forward, Range is committed to translating well-level returns from our high-quality asset base into corporate-level returns, including a free cash flow yield that is competitive not only within energy, but across the broader market . ”  

 

 

2019 Capital Spending Plans

 

Range’s 2019 capital budget is approximately $756 million.  At strip pricing, cash flow is projected to exceed spending for the year. Excess cash flow is expected to be used to reduce debt.  In addition, asset sales are being pursued to further strengthen the balance sheet.

 

The Company expects production to average between 2,325 to 2,345 Mmcfe per day in 2019, with 30% attributed to liquids production.  Approximately 90% of the capital budget is expected to be allocated to the Appalachia division and the remainder to the North Louisiana division.  In Appalachia, over 60% of activity is planned to be directed towards liquids-rich drilling, where Range’s acreage has an extensive inventory of existing pads that reduce capital costs and gathering expenses.  The liquids-rich acreage is also in close proximity to recently built infrastructure for both natural gas takeaway and natural gas liquids (“NGL”) processing. 

 

The 2019 capital budget includes approximately $685 million for drilling and recompletions (91% of the total), $51 million for leasehold, and $20 million for pipelines, facilities and other capital expenditures.  The budget includes 88 wells expected to be brought on line during the year in the Marcellus and eight wells in North Louisiana.  Similar to the 2018 program, approximately half of the 2019 Marcellus wells are planned to be drilled from existing pads.

 

2018 Capital Expenditures

 

Fourth quarter 2018 drilling expenditures of $158 million funded the drilling of 17 wells.  Drilling expenditures for the full year totaled $836 million and funded the drilling of 104 (100 net) wells during 2018.  A 100% success rate was achieved.  In addition, during 2018, $62 million was spent on acreage purchases and $10 million on gas gathering systems.  Total capital expenditures in 2018 were approximately $910 million, which was $31 million under budget for the year.

 

2018 Proved Reserves Results

 

Range previously announced 2018 proved reserves results on February 11, 2019.   Highlights from the announcement were:

 


 

2018 PV 10 value of reserves using y ear-end future strip prices was $9.9 billion

 

Year-end 2018 SEC PV 10 value of proved reserves was $13.2 billion, up $5.1 billion from prior year

 

Proved reserves increased by 18% from the prior-year to 18.1 Tcfe

 

Drill-bit finding cost of $0.22 per mcfe, including performance revisions

 

Future development costs for proved undeveloped reserves estimated to be $0.40 per mcfe

 

 

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.

 

Full Year 2018

 

GAAP revenues for 2018 totaled $3.3 billion (26% increase compared to 2017), GAAP net cash provided from operating activities including changes in working capital was $991 million, compared to $816 million in 2017. GAAP net income was a loss of $1.75 billion ($7.10 per diluted share) versus earnings of $333 million ($1.34 per diluted share) in 2017.   Full year 2018 results include a $1.6 billion impairment of goodwill associated with the 2016 MRD merger, and a $515 million impairment of unproved properties compared to $270 million in 2017, reflecting a shift in capital allocation related to North Louisiana properties. Full year 2018 results also included a loss of $11 million from asset sales compared to a gain of $24 million in 2017, $51 million in derivative losses due to increases in future commodity prices compared to a $213 million gain in the prior year and a $19 million mark-to-market gain related to the deferred compensation plan compared to a $51 million gain in the prior year.

 

Non-GAAP revenues for 2018 totaled $3.2 billion, an increase of 33% compared to 2017 and cash flow from operations before changes in working capital, a non-GAAP measure, was $1.05 billion, compared to $916 million in 2017.  Adjusted net income comparable to analysts’ estimates, a non-GAAP measure, was $279 million ($1.13 per diluted share), compared to $143 million ($0.58 per diluted share) in 2017.  

 

The following table details Range’s average production and realized pricing for full year 2018:

 

Net Production

 

Natural Gas

(Mmcf/d)

 

Oil (Bbl/d)

 

NGLs

(Bbl/d)

 

Natural Gas

Equivalent (Mmcfe/d)

 

 

 

 

 

 

 

 

 

 

 

 

 

1,502

 

11,585

 

105,001

 

2,201

 

 

 

Realized Pricing

 

 

Natural Gas

($/Mcf)

 

Oil ($/Bbl)

 

NGLs

($/Bbl)

 

Natural Gas

Equivalent ($/Mcfe)

 

 

 

 

 

 

 

 

 

 

 

 

 

Average NYMEX price

 

$3.07

 

$65.49

 

 

 

 

Differential, including basis hedging

 

(0.05)

 

(4.97)

 

 

 

 

Realized prices before NYMEX hedges

 

3.02

 

60.52

 

$24.30

 

$3.55

Settled NYMEX hedges

 

(0.04)

 

(8.92)

 

(1.69)

 

(0.16)

Average realized prices after hedges

 

$2.98

 

$51.60

 

$22.61

 

$3.39

 

2


 

Full year 2018 natural gas, NGLs and oil price realizations (including the impact of cash-settled hedges and derivative settlements which correspond to analysts’ estimates) averaged $3.39 per mcfe.  Additional detail on commodity price realizations can be found in the Supplemental Tables provided on the Company’s website.  

 

 

The 2018 average natural gas price, including the impact of basis hedging, was $3.02 per mcf, or a ($0.05) per mcf differential to NYMEX, which was significantly better than the ($0.32) differential in the prior year. The improvement in natural gas differentials compared to last year is a result of increased pipeline connectivity and compressed basis across the Appalachian and Midwest regions.

 

 

Pre-hedge NGL realizations were $24.30 per barrel, or 37% of West Texas Intermediate (“WTI”) in 2018.  Hedging decreased NGL prices by $1.69 per barrel in 2018 compared to a decrease of $2.04 per barrel in the prior year.  

 

 

Crude oil and condensate price realizations, before realized hedges, averaged $60.52 per barrel, or $4.97 below WTI, compared to $4.77 below WTI in the prior year.  Hedging decreased price by $8.92 per barrel in 2018, compared to hedge gains of $3.19 per barrel in the prior year.

 

 

2018 Unit Costs

 

The following table details Range’s unit costs per mcfe (a) :

 

Expenses

 

Full Year 2018

(per mcfe)

 

Full Year 2017

(per mcfe)

 

 

Increase (Decrease)

 

 

 

 

 

 

 

 

Direct operating

 

$  0.17

 

$  0.18

 

 

(6%)

Transportation, gathering,

    processing and compression

 

      1.39 (b)

 

   1.04

 

 

34%

Production and ad valorem taxes

 

   0.06

 

   0.06

 

 

-

General and administrative (a)

 

   0.19

 

   0.21

 

 

(10%)

Interest expense

 

   0.26

 

   0.26

 

 

-

        Total cash unit costs (c)

 

    2.07

 

    1.74

 

 

19%

Depletion, depreciation and

    amortization (DD&A)

 

   0.79

 

   0.85

 

 

(7%)

        Total unit costs plus DD&A (c)

 

$  2.86

 

$  2.59

 

 

10%

 

 

(a)

Excludes stock-based compensation, legal settlements and amortization of deferred financing costs.

 

(b)

2018 transportation, gathering, processing and compression expense reflects the change in accounting method made at the beginning of the year.  As a result of adopting the new accounting standard, expenses increased by approximately $0.22 per mcfe in 2018.  There was an equal increase to NGL revenue, resulting in zero net impact to cash flow as a result of the change in accounting method.

 

(c)

May not add due to rounding.

 

 

Fourth Quarter 2018

 

The following table details Range’s average production and realized pricing for fourth quarter 2018:

 

Net Production

 

Natural Gas

(Mmcf/d)

 

Oil (Bbl/d)

 

NGLs

(Bbl/d)

 

Natural Gas

Equivalent (Mmcfe/d)

 

 

 

 

 

 

 

 

 

 

 

 

 

1,482

 

9,932

 

101,263

 

2,149

3


 

 

 

Realized Pricing

 

 

Natural Gas

($/Mcf)

 

Oil ($/Bbl)

 

NGLs

($/Bbl)

 

Natural Gas

Equivalent ($/Mcfe)

 

 

 

 

 

 

 

 

 

 

 

 

 

Average NYMEX price

 

$3.61

 

$60.79

 

 

 

 

Differential, including basis hedging

 

(0.08)

 

(6.28)

 

 

 

 

Realized prices before NYMEX hedges

 

3.53

 

54.51

 

$24.21

 

$3.83

Settled NYMEX hedges

 

(0.63)

 

(4.82)

 

(0.12)

 

(0.46)

Average realized prices after hedges

 

$2.90

 

$49.69

 

$24.09

 

$3.37

 

Fourth 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 $3.37 per mcfe.  Additional detail on commodity price realizations can be found in the Supplemental Tables provided on the Company’s website.  

 

 

The average natural gas price, including the impact of basis hedging, was $3.53 per mcf, or an ($0.08) per mcf differential to NYMEX, which was significantly better than the ($0.35) differential during the prior-year quarter.  The improvement in natural gas differentials compared to last year is a result of increased pipeline connectivity and compressed basis across the Appalachian and Midwest regions.

 

 

Pre-hedge NGL realizations were $24.21 per barrel, or 40% of WTI.  Hedging decreased NGL prices by $0.12 per barrel compared to a decrease of $4.06 per barrel in the prior-year quarter.  

 

 

Crude oil and condensate price realizations, before realized hedges, averaged $54.51 per barrel, or $6.28 below WTI, compared to $4.63 below WTI in the prior-year quarter.  Hedging decreased price by $4.82 per barrel compared to hedge gains of $0.27 per barrel in the prior-year quarter.

 

 

Fourth Quarter Unit Costs

 

The following table details Range’s unit costs per mcfe (a) :

 

 

Expenses

 

4Q 2018

(per mcfe)

 

4Q 2017

(per mcfe)

 

 

Increase (Decrease)

 

 

 

 

 

 

 

 

Direct operating

 

$  0.18

 

$  0.19

 

 

(5%)

Transportation, gathering,

    processing and compression

 

       1.51 (b)

 

    1.00

 

 

51%

Production and ad valorem taxes

 

    0.08

 

    0.06

 

 

33%

General and administrative (a)

 

    0.16

 

    0.21

 

 

(24%)

Interest expense

 

    0.25

 

    0.25

 

 

-

        Total cash unit costs (c)

 

    2.18

 

    1.70

 

 

28%

Depletion, depreciation and

    amortization (DD&A)

 

    0.75

 

    0.82

 

 

(9%)

        Total unit costs plus DD&A (c)

 

$  2.93

 

$  2.52

 

 

16%

 

 

 

 

 

 

 

 

 

(a)

Excludes stock-based compensation, legal settlements and amortization of deferred financing costs.

 

(b)

Fourth 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 $0.23 per mcfe in fourth quarter 2018.  There was an equal increase to NGL revenue, resulting in zero net impact to cash flow as a result of the change in accounting method.

 

(c)

May not add due to rounding.

4


 

 

2018 Asset Sale

 

As previously announced, during fourth quarter 2018, Range sold a proportionately reduced 1% overriding royalty in its Washington County, Pennsylvania leases for gross proceeds of $300 million.

 

Range’s Washington County properties encompass approximately 300,000 net surface acres. The overriding royalty applies to existing and future Marcellus, Utica and Upper Devonian development on the subject leases, while excluding shallower and deeper formations.  Post-close, Range maintains a net revenue interest of approximately 82% on the subject Washington County acreage. The net proceeds were used to reduce bank debt.

 

 

Operational Discussion

 

Range previously updated its investor presentation with economic calculations. Please see www.rangeresources.com under the Investors tab, “Company Presentations” area, for the presentation entitled, “Company Presentation – February 25, 2019.”

 

The table below summarizes 2018 activity and estimates for 2019 regarding the number of wells to sales for each area.  

 

 

 

Planned Wells TIL

in 2019

 

 

Wells TIL

in 2018

 

 

 

 

 

 

SW PA Super-Rich

 

14

 

 

14

 

SW PA Wet

 

41

 

 

38

 

SW PA Dry

 

33

 

 

34

 

     Total Appalachia

 

88

 

 

86

 

 

 

 

 

 

 

 

     Total N. LA.

 

8

 

 

12

 

         Total

 

96

 

 

98

 

 

 

Appalachia Division

 

Production for the fourth quarter of 2018 averaged approximately 1,893 net Mmcfe per day from the Appalachia division, a 5% increase over the prior year.  The northeast area of the division averaged 113 net Mmcf per day during the quarter. The southwest area of the division averaged 1,780 net Mmcfe per day during the quarter, a 7% increase over the prior year.  As previously announced, in December, an operational issue at the Houston facility required the extended curtailment of both the Harmon Creek and Houston processing complexes. As a result of MarkWest’s operational downtime, Range lost approximately 10 Bcfe of production during the quarter.  Both processing complexes were returned to service in early January. 

 

Range brought on line 16 wells in southwest Appalachia during the fourth quarter, one in the super-rich area, and 15 in the wet area.  During the year, Range turned to sales a total of 86 Marcellus wells with an average lateral length of 9,388 feet.  The Company expects to run an average of three rigs in the Marcellus during 2019, and turn to sales 88 wells with an expected average lateral length of 10,800 feet.

 

North Louisiana

 

Production for the division in the fourth quarter of 2018 averaged approximately 256 net Mmcfe per day. Range expects to turn to sales eight wells in North Louisiana in 2019.  

 

 

5


Marketing and Transportation

 

Fourth quarter 2018 marked the first full quarter where Range had access to all of its contracted natural gas transportation, as Energy Transfer’s Rover project provided additional outlets to the Midwest and Gulf Coast in September.  The fourth quarter of 2018 natural gas differential of $0.08 under NYMEX is the best fourth quarter differential Range has seen since 2012, due in large part to the addition of transportation out of Appalachia.  Going forward, Range expects to keep its natural gas transportation full and sell incremental gas production into local markets which have improved due to the recently added takeaway infrastructure.  

 

Range has capacity on the Mariner East 1 pipeline for a combined 40,000 barrels per day of ethane and propane.  As the only producer with propane capacity on Mariner East 1, Range has been able to capture premiums to the Mont Belvieu index price by exporting the majority of its propane to international markets since early 2016.  In addition, the Company sent the majority of its normal butane and remaining propane volumes during the summer to Marcus Hook for export via local rail.  As the Company continues to develop its liquids acreage, additional outlets for NGL production are beneficial in providing stability to NGL price, especially during the summer when in-basin demand is low.  Range has taken capacity on Mariner East 2 for a combined 20,000 barrels per day of propane and butane, starting in April 2020, which gives the Company additional flexibility in marketing NGL production while participating in the expected local market improvements.  Importantly, Range expects to fill the incremental capacity with existing propane and butane volumes, leaving flexibility to sell incremental NGLs in-basin.

 

In January 2019, Range lost access to its capacity on Sunoco’s Mariner East 1 pipeline following the appearance of a subsidence along the pipeline route.  As a result of the outage, Range is utilizing available capacity on the recently commissioned Mariner East 2 pipeline to continue moving its propane to the Marcus Hook terminal. For ethane, Range has multiple options for marketing its production, including the ability to sell ethane as natural gas.  While not materially altering corporate cash flows, the delayed restart of MarkWest plants and the Mariner East outage have reduced production volumes, and as a result, Range’s first quarter guidance of 2,225 Mmcfe per day reflects the estimated production impact.

 

 

Guidance – 2019  

 

Production per day Guidance

 

Production for the full-year 2019 is expected to average approximately 2,325 to 2,345 Mmcfe per day, or 6% year-over-year growth at the midpoint.  

 

First quarter 2019 production is expected to average approximately 2,225 Mmcfe per day.

 

1Q 2019 Expense Guidance  

 

Direct operating expense:

$0.17 - $0.19 per mcfe

Transportation, gathering, processing and compression

   expense:

$1.48 - $1.52 per mcfe

Production tax expense:

$0.05 - $0.06 per mcfe

Exploration expense:

$6.0 - $9.0 million

Unproved property impairment expense:

$7.0 - $10.0 million

G&A expense:

$0.20 - $0.22 per mcfe

Interest expense:

$0.24 - $0.26 per mcfe

DD&A expense:

$0.74 - $0.78 per mcfe

Net brokered gas marketing (gain) expense:

~ ($3.0 million)

 

1Q 2019 Natural Gas Price Differential Guidance NYMEX plus $0.01

 

 

 

Full Year 2019 Price Guidance

6


 

Based on current market pricing indications, Range expects to average the following pre-hedge differentials for its production in 2019.  

 

Natural Gas:

NYMEX minus $0.15 to $0.20

Natural Gas Liquids (including ethane):

36 % - 38% of WTI

Oil/Condensate:

WTI minus $6.00 to $8.00

 

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. At year-end 2018, Range had over 75% of its expected 2019 natural gas production hedged at a weighted average floor price of $2.86 per mmbtu.  Similarly, Range had hedged approximately 70% of its 2019 projected crude oil production at an average floor price of $56.23.   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 as of December 31, 2018 was a gain of $4.8 million, compared to a loss of $7.8 million at December 31, 2017.    

 

Conference Call Information

A conference call to review the financial results is scheduled on Tuesday, February 26 at 9:00 a.m. ET. To participate in the call, please dial 866-900-7525 and provide conference code 6972159 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 March 26.

Non-GAAP Financial Measures

 

Adjusted net income comparable to analysts’ estimates as set forth in this release represents income or loss from operations before income taxes adjusted for certain non-cash items (detailed in the accompanying table) less income taxes.  We believe adjusted net income comparable to analysts’ estimates is calculated on the same basis as analysts’ estimates and that many investors use this published research in making investment decisions and evaluating operational trends of the Company and its performance relative to other oil and gas producing companies.  Diluted earnings per share (adjusted) as set forth in this release represents adjusted net income comparable to analysts’ estimates on a diluted per share basis.  A table is included which reconciles income or loss from operations to adjusted net income comparable to analysts’ estimates and diluted earnings per share (adjusted).  On its website, the Company provides additional comparative information on prior periods along with non-GAAP revenue disclosures.  

 

Cash flow from operations before changes in working capital (sometimes referred to as “adjusted cash flow”) as defined in this release represents net cash provided by operations before changes in working capital and exploration expense adjusted for certain non-cash compensation items.  Cash flow from operations before changes in working capital is widely accepted by the investment community as a financial indicator of an oil and gas company’s ability to generate cash to internally fund exploration and development activities and to service debt.  Cash flow from operations before changes in working capital is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry.  In turn, many investors use this published research in making investment decisions.  Cash flow from operations before changes in working capital is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operations, investing, or financing activities as an indicator of cash flows, or as a measure of liquidity.  A table is included which reconciles net cash provided by operations to cash flow from operations before changes in working capital as used in this release.  On

7


its website, the Company provides additional comparative information on prior periods for cash flow, cash margins and non-GAAP earnings as used in this release.

 

The cash prices realized for oil and natural gas production, including the amounts realized on cash-settled derivatives and net of transportation, gathering, processing and compression expense, is a critical component in the Company’s performance tracked by investors and professional research analysts in valuing, comparing, rating and providing investment recommendations and forecasts of companies in the oil and gas exploration and production industry.  In turn, many investors use this published research in making investment decisions.  Due to the GAAP disclosures of various derivative transactions and third-party transportation, gathering, processing and compression expense, such information is now reported in various lines of the income statement.  The Company believes that it is important to furnish a table reflecting the details of the various components of each income statement line to better inform the reader of the details of each amount and provide a summary of the realized cash-settled amounts and third-party transportation, gathering, processing and compression expense, which were historically reported as natural gas, NGLs and oil sales.  This information is intended to bridge the gap between various readers’ understanding and fully disclose the information needed.

 

The Company discloses in this release the detailed components of many of the single line items shown in the GAAP financial statements included in the Company’s Annual Report on Form 10-K.  The Company believes that it is important to furnish this detail of the various components comprising each line of the Statements of Operations to better inform the reader of the details of each amount, the changes between periods and the effect on its financial results.

  

Finding and development cost per unit is a non-GAAP metric used in the exploration and production industry by companies, investors and analysts. Drill-bit development cost per mcfe is based on estimated and unaudited drilling, development and exploration costs incurred divided by the total of reserve additions, performance and price revisions.  These calculations do not include the future development costs required for the development of proved undeveloped reserves. This reserves metric may not be comparable to similarly titled measurements used by other companies.  The U.S. Securities and Exchange Commission (the “SEC”) method of computing finding costs contains additional cost components and results in a higher number.  A reconciliation of the two methods is shown on our website at www.rangeresources.com .

 

The reserve replacement ratio and finding and development cost per unit are statistical indicators that have limitations, including their predictive and comparative value.  As an annual measure, the reserve replacement ratio can be limited because it may vary widely based on the extent and timing of new discoveries and the varying effects of changes in prices and well performance.  In addition, since the reserve replacement ratio and finding and development cost per unit do not consider the cost or timing of future production of new reserves, such measures may not be an adequate measure of value creation.  

 

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 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”,

8


“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.

 


9


 

2019-04

SOURCE:   Range Resources Corporation

 

 

Investor Contacts:

 

Laith Sando, Vice President – Investor Relations

817-869-4267

lsando@rangeresources.com

 

Michael Freeman, Director – Investor Relations & Hedging

817-869-4264

mfreeman@rangeresources.com

 

John Durham, Senior Financial Analyst

817-869-1538

jdurham@rangeresources.com

 

Media Contact:

 

Michael Mackin, Director of External Affairs

724-743-6776

mmackin@rangeresources.com

 

www.rangeresources.com


10


RANGE RESOURCES CORPORATION

STATEMENTS OF OPERATIONS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Based on GAAP reported earnings with additional

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

details of items included in each line in Form 10-K

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Unaudited, in thousands, except per share data)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended December 31,

 

Twelve Months Ended December 31,

 

 

2018

 

 

 

2017

 

 

 

%

 

 

 

2018

 

 

 

2017

 

 

 

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues and other income:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas, NGLs and oil sales (a)

$

756,627

 

 

$

603,159

 

 

 

 

 

 

$

2,851,077

 

 

$

2,176,287

 

 

 

 

 

Derivative fair value (loss)/income

 

100,698

 

 

 

25,024

 

 

 

 

 

 

 

(51,192

)

 

 

213,350

 

 

 

 

 

Brokered natural gas, marketing and other (b)

 

215,270

 

 

 

50,732

 

 

 

 

 

 

 

482,044

 

 

 

219,474

 

 

 

 

 

ARO settlement gain (loss) (b)

 

(59

)

 

 

(17

)

 

 

 

 

 

 

(71

)

 

 

47

 

 

 

 

 

Other (b)

 

101

 

 

 

134

 

 

 

 

 

 

 

787

 

 

 

1,872

 

 

 

 

 

Total revenues and other income

 

1,072,637

 

 

 

679,032

 

 

 

58

%

 

 

3,282,645

 

 

 

2,611,030

 

 

 

26

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Direct operating

 

34,953

 

 

 

37,424

 

 

 

 

 

 

 

137,422

 

 

 

132,192

 

 

 

 

 

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

 

442

 

 

 

497

 

 

 

 

 

 

 

2,109

 

 

 

2,060

 

 

 

 

 

Transportation, gathering, processing and compression  

 

298,716

 

 

 

200,300

 

 

 

 

 

 

 

1,117,816

 

 

 

761,183

 

 

 

 

 

Production and ad valorem taxes  

 

16,656

 

 

 

11,757

 

 

 

 

 

 

 

46,149

 

 

 

42,882

 

 

 

 

 

Brokered natural gas and marketing

 

221,175

 

 

 

50,734

 

 

 

 

 

 

 

494,595

 

 

 

218,874

 

 

 

 

 

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

 

451

 

 

 

397

 

 

 

 

 

 

 

1,452

 

 

 

1,437

 

 

 

 

 

Exploration

 

10,206

 

 

 

6,747

 

 

 

 

 

 

 

32,196

 

 

 

50,920

 

 

 

 

 

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

 

394

 

 

 

1,146

 

 

 

 

 

 

 

1,921

 

 

 

2,742

 

 

 

 

 

Abandonment and impairment of unproved properties  

 

441,750

 

 

 

217,544

 

 

 

 

 

 

 

514,994

 

 

 

269,725

 

 

 

 

 

General and administrative  

 

30,785

 

 

 

41,167

 

 

 

 

 

 

 

152,040

 

 

 

150,786

 

 

 

 

 

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

 

5,474

 

 

 

39,717

 

 

 

 

 

 

 

43,806

 

 

 

74,873

 

 

 

 

 

General and administrative – lawsuit settlements

 

13,581

 

 

 

(831

)

 

 

 

 

 

 

14,966

 

 

 

6,197

 

 

 

 

 

General and administrative – bad debt expense  

 

250

 

 

 

500

 

 

 

 

 

 

 

(1,000

)

 

 

1,550

 

 

 

 

 

Termination costs

 

 

 

 

(278

)

 

 

 

 

 

 

(373

)

 

 

2,106

 

 

 

 

 

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

 

 

 

 

(1

)

 

 

 

 

 

 

 

 

 

1,664

 

 

 

 

 

Deferred compensation plan (d)

 

(18,072

)

 

 

(14,077

)

 

 

 

 

 

 

(18,631

)

 

 

(50,915

)

 

 

 

 

Interest expense

 

50,237

 

 

 

49,629

 

 

 

 

 

 

 

205,970

 

 

 

188,450

 

 

 

 

 

Interest expense – amortization of deferred financing costs (e)

 

(1,076

)

 

 

1,844

 

 

 

 

 

 

 

4,239

 

 

 

7,229

 

 

 

 

 

Depletion, depreciation and amortization  

 

147,909

 

 

 

162,918

 

 

 

 

 

 

 

635,467

 

 

 

624,992

 

 

 

 

 

Impairment of proved property

 

 

 

 

 

 

 

 

 

 

 

22,614

 

 

 

63,679

 

 

 

 

 

Impairment of goodwill

 

1,641,197

 

 

 

 

 

 

 

 

 

 

1,641,197

 

 

 

 

 

 

 

 

Gain on sale of assets

 

10,815

 

 

 

(207

)

 

 

 

 

 

 

10,666

 

 

 

(23,716

)

 

 

 

 

Total costs and expenses

 

2,905,843

 

 

 

806,927

 

 

 

260

%

 

 

5,059,615

 

 

 

2,528,910

 

 

 

100

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Loss) income before income taxes

 

(1,833,206

)

 

 

(127,895

)

 

 

N.M.

 

 

 

(1,776,970

)

 

 

82,120

 

 

 

N.M.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income tax (benefit) expense:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current

 

 

 

 

17

 

 

 

 

 

 

 

 

 

 

17

 

 

 

 

 

Deferred

 

(68,784

)

 

 

(349,097

)

 

 

 

 

 

 

(30,489

)

 

 

(251,043

)

 

 

 

 

 

 

(68,784

)

 

 

(349,080

)

 

 

 

 

 

 

(30,489

)

 

 

(251,026

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net (loss) income

$

(1,764,422

)

 

$

221,185

 

 

 

N.M.

 

 

$

(1,746,481

)

 

$

333,146

 

 

 

N.M.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net (Loss) Income Per Common Share:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

$

(7.15

)

 

$

0.89

 

 

 

 

 

 

$

(7.10

)

 

$

1.34

 

 

 

 

 

Diluted

$

(7.15

)

 

$

0.89

 

 

 

 

 

 

$

(7.10

)

 

$

1.34

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted average common shares outstanding, as reported:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

246,631

 

 

 

245,281

 

 

 

1

%

 

 

246,171

 

 

 

245,091

 

 

 

0

%

Diluted

 

246,631

 

 

 

245,537

 

 

 

0

%

 

 

246,171

 

 

 

245,458

 

 

 

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-K.

(c) Costs associated with stock compensation and restricted stock amortization, which have been reflected in the categories associated

          with the direct personnel costs, which are combined with the cash costs in the 10-K.

(d) Reflects the change in market value of the vested Company stock held in the deferred compensation plan.

(e)  Included in interest expense in the 10-K.


11


RANGE RESOURCES CORPORATION

 

BALANCE SHEETS

 

 

 

 

 

 

 

(In thousands)

 

December 31,

 

 

 

December 31,

 

 

 

2018

 

 

 

2017

 

 

 

(Audited)

 

 

 

(Audited)

 

Assets

 

 

 

 

 

 

 

Current assets

$

514,232

 

 

$

370,627

 

Derivative assets

 

92,795

 

 

 

58,880

 

Goodwill

 

 

 

 

1,641,197

 

Natural gas and oil properties, successful efforts method

 

9,023,185

 

 

 

9,566,737

 

Transportation and field assets

 

9,776

 

 

 

14,666

 

Other

 

68,166

 

 

 

76,734

 

 

$

9,708,154

 

 

$

11,728,841

 

 

 

 

 

 

 

 

 

Liabilities and Stockholders’ Equity

 

 

 

 

 

 

 

Current liabilities

$

745,182

 

 

$

704,913

 

Asset retirement obligations

 

5,485

 

 

 

6,327

 

Derivative liabilities

 

4,144

 

 

 

44,233

 

 

 

 

 

 

 

 

 

Bank debt

 

932,018

 

 

 

1,208,467

 

Senior notes

 

2,856,166

 

 

 

2,851,754

 

Senior subordinated notes

 

48,677

 

 

 

48,585

 

Total debt

 

3,836,861

 

 

 

4,108,806

 

 

 

 

 

 

 

 

 

Deferred tax liability

 

666,668

 

 

 

693,356

 

Derivative liabilities

 

3,462

 

 

 

9,789

 

Deferred compensation liability

 

67,542

 

 

 

101,102

 

Asset retirement obligations and other liabilities

 

319,379

 

 

 

286,043

 

 

 

 

 

 

 

 

 

Common stock and retained earnings

 

4,060,480

 

 

 

5,776,203

 

Other comprehensive loss

 

(658

)

 

 

(1,332

)

Common stock held in treasury stock

 

(391

)

 

 

(599

)

Total stockholders’ equity

 

4,059,431

 

 

 

5,774,272

 

 

$

9,708,154

 

 

$

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 December 31,

 

Twelve Months Ended December 31,

 

 

2018

 

 

 

2017

 

 

 

%

 

 

 

2018

 

 

 

2017

 

 

 

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total revenues and other income, as reported

$

1,072,637

 

 

$

679,032

 

 

 

58

%

 

$

3,282,645

 

 

$

2,611,030

 

 

 

26

%

Adjustment for certain special items:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

(191,948

)

 

 

(27,969

)

 

 

 

 

 

 

(80,330

)

 

 

(200,233

)

 

 

 

 

ARO settlement (gain) loss

 

59

 

 

 

17

 

 

 

 

 

 

 

71

 

 

 

(47

)

 

 

 

 

Total revenues, as adjusted, non-GAAP

$

880,748

 

 

$

651,080

 

 

 

35

%

 

$

3,202,386

 

 

$

2,410,750

 

 

 

33

%

 


12


RANGE RESOURCES CORPORATION

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Unaudited in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended December 31,

 

 

Twelve Months Ended December 31,

 

 

 

2018

 

 

 

2017

 

 

 

2018

 

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net (loss) income

$

(1,764,422

)

 

$

221,185

 

 

$

(1,746,481

)

 

$

333,146

 

Adjustments to reconcile net cash provided from continuing operations:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred income tax (benefit) expense

 

(68,784

)

 

 

(349,097

)

 

 

(30,489

)

 

 

(251,043

)

Depletion, depreciation, amortization and impairment

 

147,909

 

 

 

162,918

 

 

 

658,081

 

 

 

688,671

 

Impairment of goodwill

 

1,641,197

 

 

 

 

 

 

1,641,197

 

 

 

 

Exploration dry hole costs

 

 

 

 

6

 

 

 

4

 

 

 

9,172

 

Abandonment and impairment of unproved properties

 

441,750

 

 

 

217,544

 

 

 

514,994

 

 

 

269,725

 

Derivative fair value (income) loss

 

(100,698

)

 

 

(25,024

)

 

 

51,192

 

 

 

(213,350

)

Cash settlements on derivative financial instruments that do not qualify for hedge

    accounting

 

(91,250

)

 

 

(2,945

)

 

 

(131,522

)

 

 

13,117

 

Allowance for bad debts

 

250

 

 

 

500

 

 

 

(1,000

)

 

 

1,550

 

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

 

(1,648

)

 

 

1,261

 

 

 

2,515

 

 

 

5,445

 

Deferred and stock-based compensation

 

(11,495

)

 

 

26,769

 

 

 

29,757

 

 

 

30,706

 

Loss (gain) on sale of assets and other

 

10,815

 

 

 

(207

)

 

 

10,666

 

 

 

(23,716

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Changes in working capital:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accounts receivable

 

(92,668

)

 

 

(63,172

)

 

 

(142,381

)

 

 

(102,866

)

Inventory and other

 

960

 

 

 

(1,475

)

 

 

138

 

 

 

(2,979

)

Accounts payable

 

2,255

 

 

 

1,197

 

 

 

(4,274

)

 

 

45,912

 

Accrued liabilities and other

 

101,572

 

 

 

26,262

 

 

 

138,293

 

 

 

12,764

 

Net changes in working capital

 

12,119

 

 

 

(37,188

)

 

 

(8,224

)

 

 

(47,169

)

Net cash provided from operating activities

$

215,743

 

 

$

215,722

 

 

$

990,690

 

 

$

816,254

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

RECONCILIATION OF NET CASH PROVIDED FROM OPERATING ACTIVITIES, AS REPORTED, TO CASH FLOW FROM OPERATIONS BEFORE CHANGES IN WORKING CAPITAL, a non-GAAP measure

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Unaudited, in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended December 31,

 

 

Twelve Months Ended December 31,

 

 

 

2018

 

 

 

2017

 

 

 

2018

 

 

 

2017

 

Net cash provided from operating activities, as reported

$

215,743

 

 

$

215,722

 

 

$

990,690

 

 

$

816,254

 

Net changes in working capital

 

(12,119

)

 

 

37,188

 

 

 

8,224

 

 

 

47,169

 

Exploration expense

 

10,206

 

 

 

6,741

 

 

 

32,192

 

 

 

41,748

 

Lawsuit settlements

 

13,581

 

 

 

(831

)

 

 

14,966

 

 

 

6,197

 

Termination costs

 

 

 

 

(278

)

 

 

(373

)

 

 

2,106

 

Non-cash compensation adjustment

 

815

 

 

 

1,510

 

 

 

2,695

 

 

 

2,892

 

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

$

228,226

 

 

$

260,052

 

 

$

1,048,394

 

 

$

916,366

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Unaudited, in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended December 31,

 

 

Twelve Months Ended December 31,

 

 

 

2018

 

 

 

2017

 

 

 

2018

 

 

 

2017

 

Basic:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted average shares outstanding

 

249,515

 

 

 

248,140

 

 

 

249,228

 

 

 

247,882

 

Stock held by deferred compensation plan

 

(2,884

)

 

 

(2,859

)

 

 

(3,057

)

 

 

(2,791

)

Adjusted basic

 

246,631

 

 

 

245,281

 

 

 

246,171

 

 

 

245,091

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Dilutive:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted average shares outstanding

 

249,515

 

 

 

248,140

 

 

 

249,228

 

 

 

247,882

 

Dilutive stock options under treasury method

 

(2,884

)

 

 

(2,603

)

 

 

(3,057

)

 

 

(2,424

)

Adjusted dilutive

 

246,631

 

 

 

245,537

 

 

 

246,171

 

 

 

245,458

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 


13


RANGE RESOURCES CORPORATION

 

RECONCILIATION OF NATURAL GAS, NGLs AND OIL SALES AND DERIVATIVE FAIR VALUE INCOME (LOSS) TO CALCULATED CASH REALIZED NATURAL GAS, NGLs AND OIL PRICES WITH AND WITHOUT THIRD PARTY TRANSPORTATION, GATHERING AND COMPRESSION FEES, a non-GAAP measure

 

 

 

 

 

(Unaudited, in thousands, except per unit data)

 

 

 

 

 

 

Three Months Ended December 31,

 

 

Twelve Months Ended December 31,

 

 

 

2018

 

 

 

2017

 

 

 

%

 

 

 

2018

 

 

 

2017

 

 

 

%

 

Natural gas, NGL and oil sales components:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas sales

$

481,252

 

 

$

340,965

 

 

 

 

 

 

$

1,663,832

 

 

$

1,349,945

 

 

 

 

 

NGL sales

 

225,567

 

 

 

192,232

 

 

 

 

 

 

 

931,360

 

 

 

604,672

 

 

 

 

 

Oil sales

 

49,808

 

 

 

69,962

 

 

 

 

 

 

 

255,885

 

 

 

221,650

 

 

 

 

 

Total oil and gas sales, as reported

$

756,627

 

 

$

603,159

 

 

 

25

%

 

$

2,851,077

 

 

$

2,176,267

 

 

 

31

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative fair value income (loss), as reported:

$

100,698

 

 

$

25,024

 

 

 

 

 

 

$

(51,192

)

 

$

213,350

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas

 

85,757

 

 

 

(36,412

)

 

 

 

 

 

 

29,291

 

 

 

(71,059

)

 

 

 

 

NGLs

 

1,087

 

 

 

39,733

 

 

 

 

 

 

 

64,522

 

 

 

73,192

 

 

 

 

 

Crude Oil

 

4,406

 

 

 

(376

)

 

 

 

 

 

 

37,709

 

 

 

(15,250

)

 

 

 

 

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

$

191,948

 

 

$

27,969

 

 

 

 

 

 

$

80,330

 

 

$

200,233

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Transportation, gathering, processing and compression components:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas

$

180,920

 

 

$

141,902

 

 

 

 

 

 

$

678,489

 

 

$

526,671

 

 

 

 

 

NGLs

 

117,796

 

 

 

58,398

 

 

 

 

 

 

 

439,327

 

 

 

234,512

 

 

 

 

 

Total transportation, gathering, processing and compression, as reported

$

298,716

 

 

$

200,300

 

 

 

 

 

 

$

1,117,816

 

 

$

761,183

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas sales

$

395,495

 

 

$

377,377

 

 

 

 

 

 

$

1,634,541

 

 

$

1,421,004

 

 

 

 

 

NGL sales

 

224,480

 

 

 

152,499

 

 

 

 

 

 

 

866,838

 

 

 

531,480

 

 

 

 

 

Oil sales

 

45,402

 

 

 

70,338

 

 

 

 

 

 

 

218,176

 

 

 

236,900

 

 

 

 

 

Total

$

665,377

 

 

$

600,214

 

 

 

11

%

 

$

2,719,555

 

 

$

2,189,384

 

 

 

24

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (mcf)

 

136,315,861

 

 

 

132,864,354

 

 

 

3

%

 

 

548,085,437

 

 

 

490,253,467

 

 

 

12

%

NGL (bbl)

 

9,316,151

 

 

 

9,755,481

 

 

 

-5

%

 

 

38,325,251

 

 

 

35,709,254

 

 

 

7

%

Oil (bbl)

 

913,735

 

 

 

1,380,649

 

 

 

-34

%

 

 

4,228,439

 

 

 

4,787,022

 

 

 

-12

%

Gas equivalent (mcfe) (b)

 

197,695,177

 

 

 

199,681,134

 

 

 

-1

%

 

 

803,407,577

 

 

 

733,231,123

 

 

 

10

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (mcf)

 

1,481,694

 

 

 

1,444,178

 

 

 

3

%

 

 

1,501,604

 

 

 

1,343,160

 

 

 

12

%

NGL (bbl)

 

101,263

 

 

 

106,038

 

 

 

-5

%

 

 

105,001

 

 

 

97,834

 

 

 

7

%

Oil (bbl)

 

9,932

 

 

 

15,007

 

 

 

-34

%

 

 

11,585

 

 

 

13,115

 

 

 

-12

%

Gas equivalent (mcfe) (b)  

 

2,148,861

 

 

 

2,170,447

 

 

 

-1

%

 

 

2,201,117

 

 

 

2,008,852

 

 

 

10

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average prices, excluding derivative settlements and before third party
transportation costs:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (mcf)

$

3.53

 

 

$

2.57

 

 

 

38

%

 

$

3.04

 

 

$

2.75

 

 

 

10

%

NGL (bbl)

$

24.21

 

 

$

19.71

 

 

 

23

%

 

$

24.30

 

 

$

16.93

 

 

 

44

%

Oil (bbl)

$

54.51

 

 

$

50.67

 

 

 

8

%

 

$

60.52

 

 

$

46.30

 

 

 

31

%

Gas equivalent (mcfe) (b)

$

3.83

 

 

$

3.02

 

 

 

27

%

 

$

3.55

 

 

$

2.97

 

 

 

20

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average prices, including derivative settlements before third party
transportation costs: (c)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (mcf)

$

2.90

 

 

$

2.84

 

 

 

2

%

 

$

2.98

 

 

$

2.90

 

 

 

3

%

NGL (bbl)

$

24.10

 

 

$

15.63

 

 

 

54

%

 

$

22.62

 

 

$

14.88

 

 

 

52

%

Oil (bbl)

$

49.69

 

 

$

50.95

 

 

 

-2

%

 

$

51.60

 

 

$

49.49

 

 

 

4

%

Gas equivalent (mcfe) (b)

$

3.37

 

 

$

3.01

 

 

 

12

%

 

$

3.39

 

 

$

2.99

 

 

 

13

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average prices, including derivative settlements and after third party

       transportation costs: (d)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (mcf)

$

1.57

 

 

$

1.77

 

 

 

-11

%

 

$

1.74

 

 

$

1.82

 

 

 

-4

%

NGL (bbl)

$

11.45

 

 

$

9.65

 

 

 

19

%

 

$

11.15

 

 

$

8.32

 

 

 

34

%

Oil (bbl)

$

49.69

 

 

$

50.95

 

 

 

-2

%

 

$

51.60

 

 

$

49.49

 

 

 

4

%

Gas equivalent (mcfe) (b)

$

1.85

 

 

$

2.00

 

 

 

-7

%

 

$

1.99

 

 

$

1.95

 

 

 

2

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Transportation, gathering and compression expense per mcfe

$

1.51

 

 

$

1.00

 

 

 

51

%

 

$

1.39

 

 

$

1.04

 

 

 

34

%

(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, processing and compression costs.

14


RANGE RESOURCES CORPORATION

 

RECONCILIATION OF INCOME BEFORE (LOSS) INCOME TAXES AS REPORTED TO INCOME BEFORE INCOME TAXES EXCLUDING CERTAIN ITEMS, a non-GAAP measure

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Unaudited, in thousands, except per share data)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended December 31,

 

Twelve Months Ended December 31,

 

 

2018

 

 

 

2017

 

 

 

%

 

 

 

2018

 

 

 

2017

 

 

 

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Loss) income from operations before income taxes, as reported

$

(1,833,206

)

 

$

(127,895

)

 

 

N.M.

 

 

$

(1,776,970

)

 

$

82,120

 

 

 

N.M.

 

Adjustment for certain special items:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Loss (gain) on sale of assets

 

10,815

 

 

 

(207

)

 

 

 

 

 

 

10,666

 

 

 

(23,716

)

 

 

 

 

Loss (gain) on ARO settlements

 

59

 

 

 

17

 

 

 

 

 

 

 

71

 

 

 

(47

)

 

 

 

 

Change in fair value related to derivatives prior to settlement

 

(191,948

)

 

 

(27,969

)

 

 

 

 

 

 

(80,330

)

 

 

(200,233

)

 

 

 

 

Impairment of goodwill

 

1,641,197

 

 

 

 

 

 

 

 

 

 

1,641,197

 

 

 

 

 

 

 

 

Abandonment and impairment of unproved properties

 

441,750

 

 

 

217,544

 

 

 

 

 

 

 

514,994

 

 

 

269,725

 

 

 

 

 

Impairment of proved property

 

 

 

 

 

 

 

 

 

 

 

22,614

 

 

 

63,679

 

 

 

 

 

Lawsuit settlements

 

13,581

 

 

 

(831

)

 

 

 

 

 

 

14,966

 

 

 

6,197

 

 

 

 

 

Termination costs

 

 

 

 

(278

)

 

 

 

 

 

 

(373

)

 

 

2,106

 

 

 

 

 

Termination costs – non-cash stock-based compensation

 

 

 

 

(1

)

 

 

 

 

 

 

 

 

 

1,664

 

 

 

 

 

Brokered natural gas and marketing – non-cash stock-based
compensation

 

451

 

 

 

397

 

 

 

 

 

 

 

1,452

 

 

 

1,437

 

 

 

 

 

Direct operating – non-cash stock-based compensation

 

442

 

 

 

497

 

 

 

 

 

 

 

2,109

 

 

 

2,060

 

 

 

 

 

Exploration expenses – non-cash stock-based compensation

 

394

 

 

 

1,146

 

 

 

 

 

 

 

1,921

 

 

 

2,742

 

 

 

 

 

General & administrative – non-cash stock-based compensation

 

5,474

 

 

 

39,717

 

 

 

 

 

 

 

43,806

 

 

 

74,873

 

 

 

 

 

Deferred compensation plan – non-cash adjustment

 

(18,072

)

 

 

(14,077

)

 

 

 

 

 

 

(18,631

)

 

 

(50,915

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income before income taxes, as adjusted

 

70,937

 

 

 

88,060

 

 

 

-19

%

 

 

377,492

 

 

 

231,692

 

 

 

63

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income tax expense, as adjusted

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current

 

 

 

 

17

 

 

 

 

 

 

 

 

 

 

17

 

 

 

 

 

Deferred (a)

 

18,444

 

 

 

33,446

 

 

 

 

 

 

 

98,061

 

 

 

88,738

 

 

 

 

 

Net income excluding certain items, a non-GAAP measure

$

52,493

 

 

$

54,597

 

 

 

-4

%

 

$

279,431

 

 

$

142,937

 

 

 

95

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Non-GAAP income per common share

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

$

0.21

 

 

$

0.22

 

 

 

-5

%

 

$

1.14

 

 

$

0.58

 

 

 

97

%

Diluted

$

0.21

 

 

$

0.22

 

 

 

-5

%

 

$

1.13

 

 

$

0.58

 

 

 

95

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Non-GAAP diluted shares outstanding, if dilutive

 

247,719

 

 

 

245,537

 

 

 

 

 

 

 

247,220

 

 

 

245,458

 

 

 

 

 

 

(a)    Deferred taxes for 2018 are estimated to be approximately 26% and 38% for 2017.

 

    

15


RANGE RESOURCES CORPORATION

 

RECONCILIATION OF NET (LOSS) INCOME, EXCLUDING

CERTAIN ITEMS AND ADJUSTED EARNINGS PER SHARE, non-GAAP measures

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(In thousands, except per share data)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended December 31,

 

 

Twelve Months Ended December 31,

 

 

 

2018

 

 

 

2017

 

 

 

 

2018

 

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net (loss) income, as reported

$

(1,764,422

)

 

$

221,185

 

 

 

$

(1,746,481

)

 

$

333,146

 

 

Adjustment for certain special items:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Gain) loss on sale of assets

 

10,815

 

 

 

(207

)

 

 

 

10,666

 

 

 

(23,716

)

 

Loss (gain) on ARO settlements

 

59

 

 

 

17

 

 

 

 

71

 

 

 

(47

)

 

Change in fair value related to derivatives prior to settlement

 

(191,948

)

 

 

(27,969

)

 

 

 

(80,330

)

 

 

(200,233

)

 

Impairment of goodwill

 

1,641,197

 

 

 

 

 

 

 

1,641,197

 

 

 

 

 

Impairment of proved property

 

 

 

 

 

 

 

 

22,614

 

 

 

63,679

 

 

Abandonment and impairment of unproved properties

 

441,750

 

 

 

217,544

 

 

 

 

514,994

 

 

 

269,725

 

 

Lawsuit settlements

 

13,581

 

 

 

(831

)

 

 

 

14,966

 

 

 

6,197

 

 

Termination costs

 

 

 

 

(278

)

 

 

 

(373

)

 

 

2,106

 

 

Non-cash stock-based compensation

 

6,761

 

 

 

41,756

 

 

 

 

49,288

 

 

 

82,776

 

 

Deferred compensation plan

 

(18,072

)

 

 

(14,077

)

 

 

 

(18,631

)

 

 

(50,915

)

 

Tax impact

 

(87,228

)

 

 

(382,543

)

 

 

 

(128,550

)

 

 

(339,781

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income excluding certain items, a non-GAAP measure

$

52,493

 

 

$

54,597

 

 

 

$

279,431

 

 

$

142,937

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net (loss) income per diluted share, as reported

$

(7.15

)

 

$

0.89

 

 

 

$

(7.10

)

 

$

1.34

 

 

Adjustment for certain special items per diluted share:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Gain) loss on sale of assets

 

0.04

 

 

 

(0.00

)

 

 

 

0.04

 

 

 

(0.10

)

 

Loss (gain) on ARO settlements

 

0.00

 

 

 

0.00

 

 

 

 

0.00

 

 

 

(0.00

)

 

Change in fair value related to derivatives prior to settlement

 

(0.78

)

 

 

(0.11

)

 

 

 

(0.33

)

 

 

(0.82

)

 

Impairment of goodwill

 

6.65

 

 

 

 

 

 

 

6.67

 

 

 

 

 

Impairment of proved property

 

 

 

 

 

 

 

 

0.09

 

 

 

0.26

 

 

Abandonment and impairment of unproved properties

 

1.79

 

 

 

0.89

 

 

 

 

2.09

 

 

 

1.10

 

 

Lawsuit settlements

 

0.06

 

 

 

(0.00

)

 

 

 

0.06

 

 

 

0.03

 

 

Termination costs

 

 

 

 

(0.00

)

 

 

 

(0.00

)

 

 

0.01

 

 

Non-cash stock-based compensation

 

0.03

 

 

 

0.17

 

 

 

 

0.20

 

 

 

0.34

 

 

Deferred compensation plan

 

(0.07

)

 

 

(0.06

)

 

 

 

(0.08

)

 

 

(0.21

)

 

Adjustment for rounding differences

 

(0.01

)

 

 

 

 

 

 

0.01

 

 

 

0.01

 

 

Tax impact

 

(0.35

)

 

 

(1.56

)

 

 

 

(0.52

)

 

 

(1.38

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income per diluted share, excluding certain items, a non-

     GAAP measure

$

0.21

 

 

$

0.22

 

 

 

$

1.13

 

 

$

0.58

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Adjusted earnings per share, a non-GAAP measure:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

$

0.21

 

 

$

0.22

 

 

 

$

1.14

 

 

$

0.58

 

 

Diluted

$

0.21

 

 

$

0.22

 

 

 

$

1.13

 

 

$

0.58

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 


16


RANGE RESOURCES CORPORATION

 

RECONCILIATION OF CASH MARGIN PER MCFE, a non-

GAAP measure

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Unaudited, in thousands, except per unit data)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

December 31,

 

 

 

Twelve Months Ended

December 31,

 

 

 

 

2018

 

 

 

2017

 

 

 

 

2018

 

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas, NGL and oil sales, as reported

$

756,627

 

 

$

603,159

 

 

 

$

2,851,077

 

 

$

2,176,287

 

 

Derivative fair value income (loss), as reported

 

100,698

 

 

 

25,024

 

 

 

 

(51,192

)

 

 

213,350

 

 

       Less non-cash fair value (gain) loss

 

(191,948

)

 

 

(27,969

)

 

 

 

(80,330

)

 

 

(200,233

)

 

Brokered natural gas and marketing and other, as reported

 

215,312

 

 

 

50,849

 

 

 

 

482,760

 

 

 

221,393

 

 

       Less ARO settlement and other (gains) losses

 

(42

)

 

 

(117

)

 

 

 

(716

)

 

 

(1,919

)

 

               Cash revenue applicable to production

 

880,647

 

 

 

650,946

 

 

 

 

3,201,599

 

 

 

2,408,878

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Direct operating, as reported

 

35,395

 

 

 

37,921

 

 

 

 

139,531

 

 

 

134,252

 

 

       Less direct operating stock-based compensation

 

(442

)

 

 

(497

)

 

 

 

(2,109

)

 

 

(2,060

)

 

Transportation, gathering and compression, as reported

 

298,716

 

 

 

200,300

 

 

 

 

1,117,816

 

 

 

761,183

 

 

Production and ad valorem taxes, as reported

 

16,656

 

 

 

11,757

 

 

 

 

46,149

 

 

 

42,882

 

 

Brokered natural gas and marketing, as reported

 

221,626

 

 

 

51,131

 

 

 

 

496,047

 

 

 

220,311

 

 

       Less brokered natural gas and marketing stock-based

            compensation

 

(451

)

 

 

(397

)

 

 

 

(1,452

)

 

 

(1,437

)

 

General and administrative, as reported

 

50,090

 

 

 

80,553

 

 

 

 

209,812

 

 

 

233,406

 

 

       Less G&A stock-based compensation

 

(5,474

)

 

 

(39,717

)

 

 

 

(43,806

)

 

 

(74,873

)

 

       Less lawsuit settlements

 

(13,581

)

 

 

831

 

 

 

 

(14,966

)

 

 

(6,197

)

 

Interest expense, as reported

 

49,161

 

 

 

51,473

 

 

 

 

210,209

 

 

 

195,679

 

 

       Less amortization of deferred financing costs

 

1,076

 

 

 

(1,844

)

 

 

 

(4,239

)

 

 

(7,229

)

 

               Cash expenses

 

652,772

 

 

 

391,511

 

 

 

 

2,152,992

 

 

 

1,495,917

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash margin, a non-GAAP measure

$

227,875

 

 

$

259,435

 

 

 

$

1,048,607

 

 

$

912,961

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Mmcfe produced during period

 

197,695

 

 

 

199,681

 

 

 

 

803,408

 

 

 

733,231

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash margin per mcfe

$

1.15

 

 

$

1.30

 

 

 

$

1.31

 

 

$

1.25

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

RECONCILIATION OF (LOSS) INCOME BEFORE INCOME

TAXES TO CASH MARGIN

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Unaudited, in thousands, except per unit data)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

December 31,

 

 

 

Twelve Months Ended

December 31,

 

 

 

 

2018

 

 

 

2017

 

 

 

 

2018

 

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Loss) income before income taxes, as reported

$

(1,833,206

)

 

$

(127,895

)

 

 

$

(1,776,970

)

 

$

82,120

 

 

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

     margin:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

ARO settlements and other (gains) losses

 

(42

)

 

 

(117

)

 

 

 

(716

)

 

 

(1,919

)

 

Derivative fair value (income) loss

 

(100,698

)

 

 

(25,024

)

 

 

 

51,192

 

 

 

(213,350

)

 

Net cash receipts on derivative settlements

 

(91,250

)

 

 

(2,945

)

 

 

 

(131,522

)

 

 

13,117

 

 

Exploration expense

 

10,206

 

 

 

6,747

 

 

 

 

32,196

 

 

 

50,920

 

 

Lawsuit settlements

 

13,581

 

 

 

(831

)

 

 

 

14,966

 

 

 

6,197

 

 

Termination costs

 

 

 

 

(278

)

 

 

 

(373

)

 

 

2,106

 

 

Deferred compensation plan

 

(18,072

)

 

 

(14,077

)

 

 

 

(18,631

)

 

 

(50,915

)

 

Stock-based compensation (direct operating, brokered natural gas

   and marketing, general and administrative and termination costs)

 

6,761

 

 

 

41,756

 

 

 

 

49,288

 

 

 

82,776

 

 

Interest – amortization of deferred financing costs

 

(1,076

)

 

 

1,844

 

 

 

 

4,239

 

 

 

7,229

 

 

Depletion, depreciation and amortization

 

147,909

 

 

 

162,918

 

 

 

 

635,467

 

 

 

624,992

 

 

(Gain) loss on sale of assets

 

10,815

 

 

 

(207

)

 

 

 

10,666

 

 

 

(23,716

)

 

Impairment of goodwill

 

1,641,197

 

 

 

 

 

 

 

1,641,197

 

 

 

 

 

Impairment of proved property and other assets

 

 

 

 

 

 

 

 

22,614

 

 

 

63,679

 

 

Abandonment and impairment of unproved properties

 

441,750

 

 

 

217,544

 

 

 

 

514,994

 

 

 

269,725

 

 

Cash margin, a non-GAAP measure

$

227,875

 

 

$

259,435

 

 

 

$

1,048,607

 

 

$

912,961

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

17


RANGE RESOURCES CORPORATION

 

HEDGING POSITION AS OF DECEMBER 31, 2018 – (Unaudited)

 

 

 

 

 

 

Daily Volume

 

 

 

Hedge Price

 

 

Gas   1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

1Q 2019 Swaps

 

 

 

1,385,000 Mmbtu

 

 

 

$3.05

 

 

2Q 2019 Swaps

 

 

 

1,455,000 Mmbtu

 

 

 

$2.80

 

 

3Q 2019 Swaps

 

 

 

1,455,000 Mmbtu

 

 

 

$2.80

 

 

4Q 2019 Swaps

 

 

 

1,428,478 Mmbtu

 

 

 

$2.81

 

 

 

 

 

 

 

 

 

 

 

 

 

2020 Swaps

 

 

 

80,000 Mmbtu

 

 

 

$2.77

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2019 Collar

 

 

 

1,000 bbls

 

 

 

$63 x 73

 

 

 

 

 

 

 

 

 

 

 

 

 

1H 2019 Swaps

 

 

 

7,000 bbls

 

 

 

$55.08

 

 

2H 2019 Swaps

 

 

 

7,000 bbls

 

 

 

$55.45

 

 

 

 

 

 

 

 

 

 

 

 

 

2020 Swaps

 

 

 

1,562 bbls

 

 

 

$61.05

 

 

 

 

 

 

 

 

 

 

 

 

 

C3 Propane

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

1Q 2019 Collars

 

 

 

7,000 bbls

 

 

 

$0.927 x $1.029 /gallon

 

 

2Q 2019 Collars

 

 

 

1,000 bbls

 

 

 

$0.90 x $0.96 /gallon

 

 

 

 

 

 

 

 

 

 

 

 

 

1Q 2019 Swaps

 

 

 

8,500 bbls

 

 

 

$0.963/gallon

 

 

2Q 2019 Swaps

 

 

 

8,500 bbls

 

 

 

$0.878/gallon

 

 

 

 

 

 

 

 

 

 

 

 

 

C4 Normal Butane

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

1Q 2019 Swaps

 

 

 

2,500 bbls

 

 

 

$1.221/gallon

 

 

 

 

 

 

 

 

 

 

 

 

 

C5 Natural Gasoline

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

1Q 2019 Swaps

 

 

 

3,750 bbls

 

 

 

$1.438/gallon

 

 

2Q 2019 Swaps

 

 

 

3,000 bbls

 

 

 

$1.401/gallon

 

 

3Q 2019 Swaps

 

 

 

1,500 bbls

 

 

 

$1.472/gallon

 

 

4Q 2019 Swaps

 

 

 

1,500 bbls

 

 

 

$1.475/gallon

 

 

(1)

Range also sold call swaptions of 230,000 Mmbtu/d for calendar 2020 at an average strike price of $2.80 per Mmbtu

 

 

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

 

18