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. |
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|
|
|
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|
|
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.
- 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.
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.
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.
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.
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.
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.
Investor Contacts:
Laith Sando, Vice President – Investor
Relations817-869-4267lsando@rangeresources.com
David Amend, Investor Relations Manager
817-869-4266damend@rangeresources.com
Michael Freeman, Senior Financial
Analyst817-869-4264mfreeman@rangeresources.com
Josh Stevens, Financial
Analyst817-869-1564jrstevens@rangeresources.com
Media Contact:
Michael Mackin, Director of External Affairs
724-743-6776mmackin@rangeresources.com
www.rangeresources.com
RANGE RESOURCES CORPORATION |
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STATEMENTS OF
OPERATIONS |
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Based on GAAP reported
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details of items
included in each line in Form 10-Q |
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|
|
|
|
|
(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. |
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 EndedSeptember 30, |
|
|
Nine Months EndedSeptember 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 |
% |
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 OPERATINGACTIVITIES, AS REPORTED, TO CASH
FLOW FROM OPERATIONSBEFORE 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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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. |
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 |
|
|
Nine Months Ended |
|
September 30, |
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 |
|
|
|
(0.0 |
1 |
) |
|
|
|
0.01 |
|
|
|
(0.01 |
) |
Tax
impact |
|
(0.33 |
) |
|
|
(0.04 |
) |
|
|
|
0.17 |
|
|
|
(0.90 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
(loss) per diluted share, excluding certain
items, |
$ |
0.05 |
|
|
$ |
(0.06 |
) |
|
|
$ |
0.36 |
|
|
$ |
(0.30 |
) |
a non-GAAP measure |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RANGE RESOURCES CORPORATION |
|
RECONCILIATION
OF CASH MARGIN PER MCFE, a non-GAAP measure |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited, in
thousands, except per unit data) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months EndedSeptember 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 EndedSeptember 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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
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|
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|
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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 |
|
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|
- 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
- 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
- Notes deferred premium on puts
- Incorporates international propane hedges
SEE WEBSITE FOR OTHER SUPPLEMENTAL
INFORMATION FOR THE PERIODS AND ADDITIONAL HEDGING
DETAILS
Range Resources (NYSE:RRC)
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