RANGE RESOURCES CORPORATION (NYSE:RRC) today
announced its second quarter 2017 financial results.
Highlights –
- Second quarter GAAP net income was $70 million, or $0.28 per
diluted share, compared to a net loss of $225 million, or $1.35 per
share in the prior-year quarter
- Second quarter cash margins improved to $1.09 per mcfe,
compared to $0.70 per mcfe in the prior-year quarter, an
improvement of 55%
- Cash flow from operations before changes in working capital, a
non-GAAP measure, reached $194 million, compared to $93 million in
second quarter 2016
- Record production totaled 1.945 Bcfe per day, an increase of
37% compared to the prior-year quarter
- Total unit costs continued to decline, with second quarter 2017
costs of $2.66 per mcfe, compared to $2.73 in the previous year
quarter, an improvement of 3%
- Seven-well Marcellus pad on the western edge of the super-rich
area with average IP’s per well of 29.1 Mmcfe per day (73%
liquids)
- Four-well Marcellus pad on the eastern edge of the dry gas area
with average IP’s per well of 30.0 Mmcf per day
Commenting, Jeff Ventura, the Company’s CEO
said, “Range continues to improve both operationally and
financially. Second quarter financial results continue to
build on the first quarter improvement in earnings and cash flow,
margins and total unit costs. Operationally, the Marcellus is
continuing to see improvement in well results and capital
efficiency. In southwest Pennsylvania this year, we have
drilled some of our best wells to date on our 515,000 acre
position, further demonstrating the size and quality of our acreage
position. As we look forward to the next several years and
beyond, with our extensive, core acreage positions, diversified
low-cost transportation portfolio and talented technical team,
Range is well-positioned to deliver significant shareholder
value.”
Financial Discussion
Except for generally accepted accounting
principles (“GAAP”) reported amounts, specific expense categories
exclude non-cash impairments, unrealized mark-to-market adjustment
on derivatives, non-cash stock compensation and other items shown
separately on the attached tables. “Unit costs” as used in
this release are composed of direct operating, transportation,
gathering, processing and compression, production and ad valorem
taxes, general and administrative, interest and depletion,
depreciation and amortization costs divided by production.
See “Non-GAAP Financial Measures” for a definition of each of the
non-GAAP financial measures and the tables that reconcile each of
the non-GAAP measures to their most directly comparable GAAP
financial measure.
Second Quarter 2017
GAAP revenues for the second quarter of 2017
totaled $673 million (over 6 times second quarter 2016), GAAP net
cash provided from operating activities including changes in
working capital was $185 million (125% increase as compared to
second quarter 2016) and GAAP earnings were $70 million ($0.28 per
diluted share) versus a loss of $225 million ($1.35 per diluted
share) in the prior-year quarter. Second quarter 2017
included $111 million in derivative gains due to decreased
commodity prices, compared to a $163 million loss in second quarter
2016.
Non-GAAP revenues for second quarter 2017 totaled $565 million (56%
increase compared to second quarter 2016) and cash flow from
operations before changes in working capital, a non-GAAP measure,
reached $194 million, compared to $93 million in second quarter
2016, an increase of 108%. Adjusted net income comparable to
analysts’ estimates, a non-GAAP measure, was $16 million ($0.06 per
diluted share) compared to a loss of $23 million ($0.14 per diluted
share) for second quarter 2016.
The Company’s total unit costs were 3% lower
than the second quarter of 2016, while cash unit costs were 1%
higher than the prior-year quarter. Direct operating costs
increased by $0.02 per mcfe over the prior-year quarter due to
higher workover and well service costs. Transportation,
gathering, processing and compression expense increased by $0.02
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. General and administrative,
interest and depletion, depreciation and amortization expenses per
mcfe continued to trend lower.
Expenses |
|
2Q 2017 (per
mcfe) |
|
2Q 2016(per
mcfe) |
|
|
Increase (Decrease) |
|
|
|
|
|
|
|
|
|
|
Direct operating |
|
$ |
0.17 |
|
$ |
0.15 |
|
|
13 |
% |
|
Transportation,
gathering, processing and compression |
|
|
1.08 |
|
|
1.06 |
|
|
2 |
% |
|
Production and ad
valorem taxes |
|
|
0.06 |
|
|
0.05 |
|
|
20 |
% |
|
General and
administrative |
|
|
0.21 |
|
|
0.23 |
|
|
(9 |
%) |
|
Interest expense |
|
|
0.27 |
|
|
0.29 |
|
|
(7 |
%) |
|
Total
cash unit costs(a) |
|
|
1.79 |
|
|
1.78 |
|
|
1 |
% |
|
Depletion, depreciation
and amortization |
|
|
0.86 |
|
|
0.95 |
|
|
(9 |
%) |
|
Total
unit costs(a) |
|
$ |
2.66 |
|
$ |
2.73 |
|
|
(3 |
%) |
|
|
|
|
|
|
|
|
|
|
(a) Totals may not add due to rounding.
Second 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 $2.88
per mcfe, a 15% 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 second
quarter 2017 were: natural gas – 1,313 Mmcf per day ($2.82
per mcf), NGLs – 93,673 barrels per day ($14.15 per barrel) and
crude oil and condensate – 11,569 barrels per day ($48.82 per
barrel).
- The average Company natural gas price differential including
the impact of basis hedges for second quarter 2017 improved to
minus ($0.39) per mcf, compared to minus ($0.48) in second quarter
2016. The second quarter 2017 average natural gas price,
before all hedging settlements, was $2.82 per mcf as compared to
$1.50 per mcf in the prior-year quarter.
- Pre-hedge NGL realizations improved to 30% of West Texas
Intermediate (“WTI”) crude oil in second quarter 2017, compared to
24% of WTI in second quarter 2016. Total NGL pricing per
barrel after realized cash-settled hedging improved to $14.15 for
second quarter 2017 compared to $11.57 per barrel in the prior-year
quarter. Range’s realized NGL pricing includes ethane
extraction and is net of processing and certain other
costs.
- Crude oil and condensate price realizations, before realized
hedges, for the second quarter 2017 averaged $43.52 per barrel, or
$4.84 below WTI, compared to $31.74, or $13.57 below WTI in the
prior-year quarter.
Capital Expenditures
Second quarter 2017 drilling expenditures of
$280 million funded the drilling and completion of 35 (32 net)
wells. A 100% success rate was achieved. In addition,
during the quarter, $8.6 million was incurred on acreage purchases,
$1.4 million on gas gathering systems and $7.1 million on seismic
expense. Range is on target with its $1.15 billion capital
budget for 2017.
Financial Position and
Liquidity
At June 30, 2017, Range had total debt
outstanding of $3.9 billion, before amortization of debt issuance
costs and premium, consisting of $2.9 billion in senior notes, $954
million in bank debt and $49 million in senior subordinated
notes. The outstanding bank debt of $954 million combined
with $286 million of undrawn letters of credit provides committed
liquidity of $760 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 – August 1, 2017”.
The table below summarizes second quarter
activity and the number of wells expected to be turned in line
(TIL) for the remainder of 2017:
|
|
2017 |
|
|
Wells TIL - First Quarter |
Wells TIL - Second Quarter |
Wells TIL - 3rd and 4th Quarters |
Planned Annual Total Wells to Sales |
Super-Rich Area |
|
6 |
8 |
18 |
32 |
Wet Area |
|
10 |
5 |
28 |
43 |
Dry- SW |
|
6 |
8 |
22 |
36 |
Dry- NE |
|
— |
2 |
— |
2 |
Total
Marcellus |
|
22 |
23 |
68 |
113 |
|
|
|
|
|
|
Upper Red |
|
19 |
3 |
12 |
34 |
Lower Red |
|
5 |
3 |
5 |
13 |
Pink |
|
3 |
— |
3 |
6 |
Extension Area |
|
— |
— |
3 |
3 |
Total N.
LA. |
|
27 |
6 |
23 |
56 |
|
|
|
|
|
|
Company
Total |
|
49 |
29 |
91 |
169 |
|
|
|
|
|
|
Appalachia Division
Division production for second quarter 2017
averaged 1.5 net Bcfe per day, a 9% increase over the prior-year
quarter. The southwest properties averaged 1,344 net Mmcfe
per day during the quarter, a 13% increase over the prior-year
quarter. The northeast properties averaged 155 net Mmcf per
day during the quarter, a 17% decrease over the prior-year
quarter. The division brought on line 23 wells in the second
quarter, eight in the super-rich area, five in the wet area, eight
in the southwest dry area and two in the northeast dry area.
Significantly, two exceptional pads were brought
on line in June, one on the eastern edge and one on the western
edge of Range’s southwest acreage position. When combined
with the pad announced in the first quarter on the northern portion
of the super-rich area, near the planned Harmon Creek processing
plant, and the pad announced in the fourth quarter on the southern
edge of the wet gas area, the results bolster Range’s confidence in
the quality of the 515,000 acreage position in southwest
Pennsylvania. Results from these pads are summarized
below:
- On the western edge of the super-rich area, a seven well pad
was recently completed with an average IP per well of 29.1 Mmcfe
per day (73% liquids), and an average lateral length of 10,685 feet
with 54 stages.
- On the eastern edge of the dry gas area, a four well pad was
recently brought on line with an average IP per well of 30.0 Mmcf
per day, and an average lateral length of 11,100 feet with 56
stages. Two of the four wells have lateral lengths in excess
of 15,000 feet.
- In the northern portion of Range’s super-rich acreage, Range
announced results in the first quarter from two wells brought on
line from a four well pad, near the planned Harmon Creek processing
plant. An additional two wells were brought on line in the
second quarter, with continued outstanding results. The
average IP per well for the 4 well pad is 29.5 Mmcfe per day (67%
liquids), a 30-day average IP of 19.6 Mmcfe per day and an average
lateral length of 9,197 feet with 46 stages.
- On the southern edge of our wet gas area, Range announced a
four well pad on the fourth quarter conference call now expected to
average over 4.0 Bcfe per 1,000 feet of lateral.
Range continues to improve capital efficiency by
drilling longer laterals, lowering costs and increasing recoveries
with approximately one-third of 2017 wells expected to be drilled
from existing pads. Lateral lengths for wells brought on line
in the first half of 2017 averaged approximately 7,500 feet, but
are expected to average over 9,500 feet in the second half of the
year. Recent development plans have also included the
application of technologies such as real-time data streaming,
advanced data visualization and machine learning to optimize
completions and production. Recent well results demonstrate
the potential gains from using this technology to identify
opportunities for improved performance.
North Louisiana Division
Production for the division in the second
quarter of 2017 averaged 416 net Mmcfe per day, an increase of 5%
from the previous quarter. Late in the second quarter, the
division brought on line six wells, consisting of three Upper Red
wells and three Lower Red wells.
The division continues to focus on Terryville
while methodically testing and delineating other areas.
Significant progress has been made in lowering the cost to drill
and complete a typical 7,500 foot lateral well in Terryville,
currently at $7.4 million. As previously discussed,
production from the wells brought to sales in early 2017 were below
expectations. These included wells that were drilled prior to
the acquisition, but not completed. In addition, Range
experimented with changes to completion designs and more
specifically, fluid intensity, in an attempt to mitigate the impact
to offset wells. These wells on average were stimulated with
approximately 40% less fluid per foot compared to typical
Terryville completions, while utilizing the same proppant per
foot. The initial production response in the wells has been
below expectations by a similar percentage, with a flatter decline
profile, suggesting the wells were under-stimulated. Going
forward, Range is planning to return to the larger fluid
designs.
In the expansion areas, the two wells previously announced (one
to the east and one to the west of Vernon field), continue to
perform well. Gas in place estimates for the area are 400 Bcf
per square mile and plans are underway to offset each of these
expansion wells with another horizontal well. The offset
wells are expected to spud in the third quarter with results near
year-end. In addition, the Company plans to drill two
vertical wells in the area to better determine reservoir properties
and identify the optimal target of the six potential
intervals.
Guidance – 2017
2017 Production per day
Guidance
Range’s third quarter production is expected to
be 1,970 Mmcfe per day. Production for the fourth quarter is
expected to be 2,170 Mmcfe per day, which is a 17% increase
compared to the prior-year quarter. This results in annual
production growth of 30%.
The reduction in annual production guidance is
primarily driven by early 2017 production results from North
Louisiana, as discussed above. In addition, non-recurring
timing delays on several well pads in southwest Pennsylvania will
impact our full year 2017 production.
3Q 2017 Expense Guidance
Direct
operating expense: |
$0.17 - $0.18 per
mcfe |
Transportation, gathering, processing and compression
expense: |
$1.05 - $1.07 per
mcfe |
Production tax expense: |
$0.05 - $0.06 per
mcfe |
Exploration expense: |
$15.0 - $18.0
million |
Unproved
property impairment expense: |
$20.0 - $23.0
million |
G&A
expense: |
$0.21 - $0.23 per
mcfe |
Interest
expense: |
$0.26 - $0.28 per
mcfe |
DD&A
expense: |
$0.86 - $0.88 per
mcfe |
Net
brokered gas marketing expense: |
~$3.0 million |
2017 Differentials
Based on current market pricing indications, Range expects to
receive the following pre-hedge differentials for its production in
2017.
Natural
Gas: |
NYMEX minus $0.30 |
Natural
Gas Liquids (including ethane): |
28% - 30% of WTI |
Oil/Condensate: |
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 $3.23 per mcf, and over one Bcf per day of first
quarter 2018 production hedged at $3.43. Similarly, Range has
hedged approximately 65% of its remaining 2017 projected crude oil
production at a floor price of approximately $56 and approximately
65% 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 June 30, 2017 was a loss of $10.5 million.
Conference Call Information
A conference call to review the financial
results is scheduled on Wednesday, August 2 at 9:00 a.m. ET. To
participate in the call, please dial 866-900-7525 and provide
conference code 48401322 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 September 2, 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. On its website,
the Company provides additional comparative information on prior
periods for cash flow, cash margins and non-GAAP earnings as used
in this release.
The cash prices realized for oil and natural gas
production including the amounts realized on cash-settled
derivatives and net of transportation, gathering, processing and
compression expense is a critical component in the Company’s
performance tracked by investors and professional research analysts
in valuing, comparing, rating and providing investment
recommendations and forecasts of companies in the oil and gas
exploration and production industry. In turn, many investors
use this published research in making investment decisions.
Due to the GAAP disclosures of various derivative transactions and
third-party transportation, gathering, processing and compression
expense, such information is now reported in various lines of the
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.
2017-07SOURCE: Range Resources Corporation
|
RANGE RESOURCES CORPORATION |
|
STATEMENTS OF
OPERATIONS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Based on GAAP reported
earnings with additional |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
details of items
included in each line in Form 10-Q |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited, in
thousands, except per share data) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
% |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Revenues and other
income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas, NGLs and oil sales (a) |
$ |
506,137 |
|
|
$ |
224,606 |
|
|
|
|
|
|
$ |
1,065,587 |
|
|
$ |
434,093 |
|
|
|
|
|
Derivative fair value income (loss) |
|
111,195 |
|
|
|
(162,798 |
) |
|
|
|
|
|
|
276,752 |
|
|
|
(75,890 |
) |
|
|
|
|
Brokered
natural gas, marketing and other (b) |
|
56,016 |
|
|
|
39,473 |
|
|
|
|
|
|
|
107,597 |
|
|
|
74,331 |
|
|
|
|
|
ARO
settlement (loss) (b) |
|
(40 |
) |
|
|
(6 |
) |
|
|
|
|
|
|
(40 |
) |
|
|
(8 |
) |
|
|
|
|
Other
(b) |
|
(197 |
) |
|
|
522 |
|
|
|
|
|
|
|
(130 |
) |
|
|
684 |
|
|
|
|
|
Total
revenues and other income |
|
673,111 |
|
|
|
101,797 |
|
|
|
561 |
% |
|
|
1,449,766 |
|
|
|
433,210 |
|
|
|
235 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and
expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct
operating |
|
30,898 |
|
|
|
19,975 |
|
|
|
|
|
|
|
58,397 |
|
|
|
43,441 |
|
|
|
|
|
Direct
operating – non-cash stock-based compensation (c) |
|
522 |
|
|
|
696 |
|
|
|
|
|
|
|
1,046 |
|
|
|
1,284 |
|
|
|
|
|
Transportation, gathering, processing and compression |
|
191,590 |
|
|
|
136,844 |
|
|
|
|
|
|
|
369,238 |
|
|
|
262,107 |
|
|
|
|
|
Production and ad valorem taxes |
|
9,969 |
|
|
|
6,049 |
|
|
|
|
|
|
|
19,132 |
|
|
|
11,936 |
|
|
|
|
|
Brokered
natural gas and marketing |
|
55,469 |
|
|
|
40,547 |
|
|
|
|
|
|
|
108,756 |
|
|
|
76,589 |
|
|
|
|
|
Brokered
natural gas and marketing – non-cash stock-based compensation
(c) |
|
388 |
|
|
|
378 |
|
|
|
|
|
|
|
651 |
|
|
|
894 |
|
|
|
|
|
Exploration |
|
13,970 |
|
|
|
6,414 |
|
|
|
|
|
|
|
21,967 |
|
|
|
10,637 |
|
|
|
|
|
Exploration – non-cash stock-based compensation (c) |
|
528 |
|
|
|
371 |
|
|
|
|
|
|
|
1,035 |
|
|
|
1,061 |
|
|
|
|
|
Abandonment and impairment of unproved properties |
|
5,193 |
|
|
|
7,059 |
|
|
|
|
|
|
|
9,613 |
|
|
|
17,687 |
|
|
|
|
|
General
and administrative |
|
37,203 |
|
|
|
29,968 |
|
|
|
|
|
|
|
73,158 |
|
|
|
58,391 |
|
|
|
|
|
General
and administrative – non-cash stock-based compensation (c) |
|
14,279 |
|
|
|
15,443 |
|
|
|
|
|
|
|
25,197 |
|
|
|
26,556 |
|
|
|
|
|
General
and administrative – lawsuit settlements |
|
540 |
|
|
|
403 |
|
|
|
|
|
|
|
1,163 |
|
|
|
1,324 |
|
|
|
|
|
General
and administrative – bad debt expense |
|
300 |
|
|
|
250 |
|
|
|
|
|
|
|
300 |
|
|
|
450 |
|
|
|
|
|
Memorial
merger expenses |
|
— |
|
|
|
2,621 |
|
|
|
|
|
|
|
— |
|
|
|
2,621 |
|
|
|
|
|
Termination costs |
|
(50 |
) |
|
|
5 |
|
|
|
|
|
|
|
2,400 |
|
|
|
167 |
|
|
|
|
|
Termination costs – non-cash stock-based compensation (c) |
|
(46 |
) |
|
|
— |
|
|
|
|
|
|
|
1,696 |
|
|
|
— |
|
|
|
|
|
Deferred
compensation plan (d) |
|
(14,466 |
) |
|
|
25,746 |
|
|
|
|
|
|
|
(27,635 |
) |
|
|
41,802 |
|
|
|
|
|
Interest
expense |
|
47,926 |
|
|
|
37,758 |
|
|
|
|
|
|
|
95,027 |
|
|
|
75,497 |
|
|
|
|
|
Depletion, depreciation and amortization |
|
152,504 |
|
|
|
122,390 |
|
|
|
|
|
|
|
302,325 |
|
|
|
242,951 |
|
|
|
|
|
Impairment of proved properties and other assets |
|
— |
|
|
|
— |
|
|
|
|
|
|
|
— |
|
|
|
43,040 |
|
|
|
|
|
(Gain)
loss on sale of assets |
|
(807 |
) |
|
|
3,304 |
|
|
|
|
|
|
|
(23,407 |
) |
|
|
4,947 |
|
|
|
|
|
Total
costs and expenses |
|
545,910 |
|
|
|
456,221 |
|
|
|
20 |
% |
|
|
1,040,059 |
|
|
|
923,382 |
|
|
|
13 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before
income taxes |
|
127,201 |
|
|
|
(354,424 |
) |
|
|
|
|
|
|
409,707 |
|
|
|
(490,172 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense
(benefit): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
— |
|
|
|
— |
|
|
|
|
|
|
|
— |
|
|
|
— |
|
|
|
|
|
Deferred |
|
57,651 |
|
|
|
(129,488 |
) |
|
|
|
|
|
|
170,046 |
|
|
|
(171,464 |
) |
|
|
|
|
|
|
57,651 |
|
|
|
(129,488 |
) |
|
|
|
|
|
|
170,046 |
|
|
|
(171,464 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
(loss) |
$ |
69,550 |
|
|
$ |
(224,936 |
) |
|
|
|
|
|
$ |
239,661 |
|
|
$ |
(318,708 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income (Loss) Per Common Share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
$ |
0.28 |
|
|
$ |
(1.35 |
) |
|
|
|
|
|
$ |
0.97 |
|
|
$ |
(1.91 |
) |
|
|
|
|
Diluted |
$ |
0.28 |
|
|
$ |
(1.35 |
) |
|
|
|
|
|
$ |
0.97 |
|
|
$ |
(1.91 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common
shares outstanding, as reported: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
245,177 |
|
|
|
167,126 |
|
|
|
47 |
% |
|
|
244,916 |
|
|
|
166,964 |
|
|
|
47 |
% |
Diluted |
|
245,335 |
|
|
|
167,126 |
|
|
|
47 |
% |
|
|
245,242 |
|
|
|
166,964 |
|
|
|
47 |
% |
(a) See separate natural gas, NGLs and oil sales
information table.(b) Included in Brokered natural gas,
marketing and other revenues in the 10-Q.(c) Costs associated
with stock compensation and restricted stock amortization, which
have been reflected in the categories associated
with the direct personnel costs, which are combined with the
cash costs in the 10-Q.(d) Reflects the change in market
value of the vested Company stock held in the deferred compensation
plan.
|
|
RANGE RESOURCES CORPORATION |
|
|
|
BALANCE
SHEETS |
|
|
|
|
|
|
|
(In thousands) |
|
June
30, |
|
|
|
December 31, |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
(Unaudited) |
|
|
|
(Audited) |
|
Assets |
|
|
|
|
|
|
|
Current
assets |
$ |
280,055 |
|
|
$ |
268,605 |
|
Derivative assets |
|
97,429 |
|
|
|
13,483 |
|
Goodwill |
|
1,646,710 |
|
|
|
1,654,292 |
|
Natural
gas and oil properties, successful efforts method |
|
9,505,442 |
|
|
|
9,256,337 |
|
Transportation and field assets |
|
16,160 |
|
|
|
16,873 |
|
Other |
|
75,540 |
|
|
|
72,655 |
|
|
$ |
11,621,336 |
|
|
$ |
11,282,245 |
|
|
|
|
|
|
|
|
|
Liabilities and
Stockholders’ Equity |
|
|
|
|
|
|
|
Current
liabilities |
$ |
584,821 |
|
|
$ |
530,373 |
|
Asset
retirement obligations |
|
7,271 |
|
|
|
7,271 |
|
Derivative liabilities |
|
4,900 |
|
|
|
165,009 |
|
|
|
|
|
|
|
|
|
Bank
debt |
|
949,948 |
|
|
|
876,428 |
|
Senior
notes |
|
2,850,100 |
|
|
|
2,848,591 |
|
Senior
subordinated notes |
|
48,541 |
|
|
|
48,498 |
|
Total
debt |
|
3,848,589 |
|
|
|
3,773,517 |
|
|
|
|
|
|
|
|
|
Deferred
tax liability |
|
1,114,583 |
|
|
|
943,343 |
|
Derivative liabilities |
|
541 |
|
|
|
24,491 |
|
Deferred
compensation liability |
|
96,854 |
|
|
|
119,231 |
|
Asset
retirement obligations and other liabilities |
|
301,886 |
|
|
|
310,642 |
|
|
|
|
|
|
|
|
|
Common
stock and retained earnings |
|
5,662,490 |
|
|
|
5,409,577 |
|
Common
stock held in treasury stock |
|
(599 |
) |
|
|
(1,209 |
) |
Total
stockholders’ equity |
|
5,661,891 |
|
|
|
5,408,368 |
|
|
$ |
11,621,336 |
|
|
$ |
11,282,245 |
|
|
|
|
|
|
|
|
|
RECONCILIATION OF TOTAL REVENUES AND OTHER INCOME TO TOTAL
REVENUE EXCLUDING CERTAIN ITEMS, a non-GAAP
measure |
(Unaudited, in
thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
|
|
|
2017 |
|
|
|
2016 |
|
|
|
% |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues and
other income, as reported |
$ |
673,111 |
|
|
$ |
101,797 |
|
|
|
561 |
% |
|
$ |
1,449,766 |
|
|
$ |
433,210 |
|
|
|
235 |
% |
Adjustment for certain
special items: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
change in fair value related to derivatives prior to settlement
(gain) loss |
|
(107,809 |
) |
|
|
260,876 |
|
|
|
|
|
|
|
(277,547 |
) |
|
|
283,434 |
|
|
|
|
|
ARO
settlement loss |
|
40 |
|
|
|
6 |
|
|
|
|
|
|
|
40 |
|
|
|
8 |
|
|
|
|
|
Total revenues, as
adjusted, non-GAAP |
$ |
565,342 |
|
|
$ |
362,679 |
|
|
|
56 |
% |
|
$ |
1,172,259 |
|
|
$ |
716,652 |
|
|
|
64 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RANGE RESOURCES CORPORATION |
|
CASH FLOWS FROM
OPERATING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited in
thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
|
Six Months Ended June 30, |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
$ |
69,550 |
|
|
$ |
(224,936 |
) |
|
$ |
239,661 |
|
|
$ |
(318,708 |
) |
Adjustments to
reconcile net cash provided from continuing operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
income tax expense (benefit) |
|
57,651 |
|
|
|
(129,488 |
) |
|
|
170,046 |
|
|
|
(171,464 |
) |
Depletion, depreciation, amortization and impairment |
|
152,504 |
|
|
|
122,390 |
|
|
|
302,325 |
|
|
|
285,991 |
|
Exploration dry hole costs |
|
161 |
|
|
|
— |
|
|
|
161 |
|
|
|
— |
|
Abandonment and impairment of unproved properties |
|
5,193 |
|
|
|
7,059 |
|
|
|
9,613 |
|
|
|
17,687 |
|
Derivative fair value adjustment |
|
(111,195 |
) |
|
|
162,798 |
|
|
|
(276,752 |
) |
|
|
75,890 |
|
Cash
settlements on derivative financial instruments that do not qualify
for hedge accounting |
|
3,387 |
|
|
|
98,078 |
|
|
|
(794 |
) |
|
|
207,544 |
|
Allowance
for bad debts |
|
300 |
|
|
|
250 |
|
|
|
300 |
|
|
|
450 |
|
Amortization of deferred issuance costs, loss on extinguishment of
debt, and other |
|
1,247 |
|
|
|
1,730 |
|
|
|
2,557 |
|
|
|
3,437 |
|
Deferred
and stock-based compensation |
|
990 |
|
|
|
42,590 |
|
|
|
1,952 |
|
|
|
71,718 |
|
(Gain)
loss on sale of assets and other |
|
(807 |
) |
|
|
3,304 |
|
|
|
(23,407 |
) |
|
|
4,947 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes
in working capital: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
receivable |
|
(8,920 |
) |
|
|
23,203 |
|
|
|
(13,610 |
) |
|
|
41,955 |
|
Inventory
and other |
|
848 |
|
|
|
5,167 |
|
|
|
3,716 |
|
|
|
10,500 |
|
Accounts
payable |
|
(5,958 |
) |
|
|
(31,116 |
) |
|
|
18,426 |
|
|
|
(19,194 |
) |
Accrued
liabilities and other |
|
20,515 |
|
|
|
1,387 |
|
|
|
(22,866 |
) |
|
|
(37,552 |
) |
Net
changes in working capital |
|
6,485 |
|
|
|
(1,359 |
) |
|
|
(14,334 |
) |
|
|
(4,291 |
) |
Net cash
provided from operating activities |
$ |
185,466 |
|
|
$ |
82,416 |
|
|
$ |
411,328 |
|
|
$ |
173,201 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RECONCILIATION OF NET CASH PROVIDED FROM OPERATING
ACTIVITIES, AS REPORTED, TO CASH FLOW FROM OPERATIONS BEFORE
CHANGES IN WORKING CAPITAL, a non-GAAP measure |
|
(Unaudited, in
thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
|
Six Months Ended June 30, |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
2017 |
|
|
|
2016 |
|
Net cash provided from
operating activities, as reported |
$ |
185,466 |
|
|
$ |
82,416 |
|
|
$ |
411,328 |
|
|
$ |
173,201 |
|
Net
changes in working capital |
|
(6,485 |
) |
|
|
1,359 |
|
|
|
14,334 |
|
|
|
4,291 |
|
Exploration expense |
|
13,809 |
|
|
|
6,414 |
|
|
|
21,806 |
|
|
|
10,637 |
|
Memorial
merger expenses |
|
— |
|
|
|
2,621 |
|
|
|
— |
|
|
|
2,621 |
|
Lawsuit
settlements |
|
540 |
|
|
|
403 |
|
|
|
1,163 |
|
|
|
1,324 |
|
Termination costs |
|
(50 |
) |
|
|
5 |
|
|
|
2,400 |
|
|
|
167 |
|
Non-cash
compensation adjustment |
|
801 |
|
|
|
126 |
|
|
|
1,092 |
|
|
|
42 |
|
Cash flow from
operations before changes in working capital – non-GAAP
measure |
$ |
194,081 |
|
|
$ |
93,344 |
|
|
$ |
452,123 |
|
|
$ |
192,283 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ADJUSTED
WEIGHTED AVERAGE SHARES OUTSTANDING |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited, in
thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
|
|
Six Months Ended June 30, |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
2017 |
|
|
|
2016 |
|
Basic: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares
outstanding |
|
247,852 |
|
|
|
169,907 |
|
|
|
247,622 |
|
|
|
169,745 |
|
Stock held by deferred
compensation plan |
|
(2,675 |
) |
|
|
(2,781 |
) |
|
|
(2,706 |
) |
|
|
(2,781 |
) |
Adjusted
basic |
|
245,177 |
|
|
|
167,126 |
|
|
|
244,916 |
|
|
|
166,964 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dilutive: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares
outstanding |
|
247,852 |
|
|
|
169,907 |
|
|
|
247,622 |
|
|
|
169,745 |
|
Dilutive stock options
under treasury method |
|
(2,517 |
) |
|
|
(2,781 |
) |
|
|
(2,380 |
) |
|
|
(2,781 |
) |
Adjusted
dilutive |
|
245,335 |
|
|
|
167,126 |
|
|
|
245,242 |
|
|
|
166,964 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RANGE RESOURCES CORPORATION |
|
|
|
RECONCILIATION OF NATURAL GAS, NGLs AND OIL SALES AND
DERIVATIVE FAIR VALUE INCOME (LOSS) TO CALCULATED CASH REALIZED
NATURAL GAS, NGLs AND OIL PRICES WITH AND WITHOUT THIRD PARTY
TRANSPORTATION, GATHERING AND COMPRESSION FEES, a non-GAAP
measure |
|
(Unaudited, in
thousands, except per unit data) |
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
% |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
% |
|
Natural gas, NGL and
oil sales components: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas sales |
$ |
336,534 |
|
|
$ |
124,187 |
|
|
|
|
|
|
$ |
707,886 |
|
|
$ |
266,622 |
|
|
|
|
|
NGL
sales |
|
123,784 |
|
|
|
73,456 |
|
|
|
|
|
|
|
261,847 |
|
|
|
123,618 |
|
|
|
|
|
Oil
sales |
|
45,819 |
|
|
|
26,963 |
|
|
|
|
|
|
|
95,854 |
|
|
|
43,853 |
|
|
|
|
|
Total oil and gas
sales, as reported |
$ |
506,137 |
|
|
$ |
224,606 |
|
|
|
125 |
% |
|
$ |
1,065,587 |
|
|
$ |
434,093 |
|
|
|
145 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative fair value
income (loss), as reported: |
$ |
111,195 |
|
|
$ |
(162,798 |
) |
|
|
|
|
|
$ |
276,752 |
|
|
$ |
(75,890 |
) |
|
|
|
|
Cash settlements on
derivative financial instruments – (gain) loss: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas |
|
(942 |
) |
|
|
(84,648 |
) |
|
|
|
|
|
|
(8,397 |
) |
|
|
(170,163 |
) |
|
|
|
|
NGLs |
|
3,131 |
|
|
|
(6,003 |
) |
|
|
|
|
|
|
17,464 |
|
|
|
(16,881 |
) |
|
|
|
|
Crude
Oil |
|
(5,575 |
) |
|
|
(7,427 |
) |
|
|
|
|
|
|
(8,272 |
) |
|
|
(20,500 |
) |
|
|
|
|
Total change in fair
value related to derivatives prior to settlement, a non-GAAP
measure |
$ |
107,809 |
|
|
$ |
(260,876 |
) |
|
|
|
|
|
$ |
277,547 |
|
|
$ |
(283,434 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation,
gathering, processing and compression components: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas |
$ |
129,557 |
|
|
$ |
96,298 |
|
|
|
|
|
|
$ |
251,750 |
|
|
$ |
188,890 |
|
|
|
|
|
NGLs |
|
62,033 |
|
|
|
40,546 |
|
|
|
|
|
|
|
117,488 |
|
|
|
73,217 |
|
|
|
|
|
Total transportation,
gathering, processing and compression, as reported |
$ |
191,590 |
|
|
$ |
136,844 |
|
|
|
|
|
|
$ |
369,238 |
|
|
$ |
262,107 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, NGL and
oil sales, including cash-settled derivatives: (c) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas sales |
$ |
337,476 |
|
|
$ |
208,835 |
|
|
|
|
|
|
$ |
716,283 |
|
|
$ |
436,785 |
|
|
|
|
|
NGL
sales |
|
120,653 |
|
|
|
79,459 |
|
|
|
|
|
|
|
244,383 |
|
|
|
140,499 |
|
|
|
|
|
Oil
sales |
|
51,394 |
|
|
|
34,390 |
|
|
|
|
|
|
|
104,126 |
|
|
|
64,353 |
|
|
|
|
|
Total |
$ |
509,523 |
|
|
$ |
322,684 |
|
|
|
58 |
% |
|
|
1,064,792 |
|
|
|
641,637 |
|
|
|
66 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production of oil and
gas during the periods (a): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (mcf) |
|
119,487,827 |
|
|
|
82,997,371 |
|
|
|
44 |
% |
|
|
235,744,164 |
|
|
|
167,864,741 |
|
|
|
40 |
% |
NGL
(bbl) |
|
8,524,267 |
|
|
|
6,865,948 |
|
|
|
24 |
% |
|
|
17,060,995 |
|
|
|
12,840,682 |
|
|
|
33 |
% |
Oil
(bbl) |
|
1,052,784 |
|
|
|
849,538 |
|
|
|
24 |
% |
|
|
2,118,070 |
|
|
|
1,693,879 |
|
|
|
25 |
% |
Gas equivalent (mcfe)
(b) |
|
176,950,133 |
|
|
|
129,290,287 |
|
|
|
37 |
% |
|
|
350,818,554 |
|
|
|
255,072,107 |
|
|
|
38 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production of oil and
gas – average per day (a): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (mcf) |
|
1,313,053 |
|
|
|
912,059 |
|
|
|
44 |
% |
|
|
1,302,454 |
|
|
|
922,334 |
|
|
|
41 |
% |
NGL
(bbl) |
|
93,673 |
|
|
|
75,450 |
|
|
|
24 |
% |
|
|
94,260 |
|
|
|
70,553 |
|
|
|
34 |
% |
Oil
(bbl) |
|
11,569 |
|
|
|
9,336 |
|
|
|
24 |
% |
|
|
11,702 |
|
|
|
9,307 |
|
|
|
26 |
% |
Gas equivalent (mcfe)
(b) |
|
1,944,507 |
|
|
|
1,420,772 |
|
|
|
37 |
% |
|
|
1,938,224 |
|
|
|
1,401,495 |
|
|
|
38 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices,
including cash-settled hedges that qualify for hedge accounting
before third party transportation costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (mcf) |
$ |
2.82 |
|
|
$ |
1.50 |
|
|
|
88 |
% |
|
$ |
3.00 |
|
|
$ |
1.59 |
|
|
|
89 |
% |
NGL
(bbl) |
$ |
14.52 |
|
|
$ |
10.70 |
|
|
|
36 |
% |
|
$ |
15.35 |
|
|
$ |
9.63 |
|
|
|
59 |
% |
Oil
(bbl) |
$ |
43.52 |
|
|
$ |
31.74 |
|
|
|
37 |
% |
|
$ |
45.26 |
|
|
$ |
25.89 |
|
|
|
75 |
% |
Gas equivalent (mcfe)
(b) |
$ |
2.86 |
|
|
$ |
1.74 |
|
|
|
64 |
% |
|
$ |
3.04 |
|
|
$ |
1.70 |
|
|
|
79 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices,
including cash-settled hedges and derivatives before third party
transportation costs: (c) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (mcf) |
$ |
2.82 |
|
|
$ |
2.52 |
|
|
|
12 |
% |
|
$ |
3.04 |
|
|
$ |
2.60 |
|
|
|
17 |
% |
NGL
(bbl) |
$ |
14.15 |
|
|
$ |
11.57 |
|
|
|
22 |
% |
|
$ |
14.32 |
|
|
$ |
10.94 |
|
|
|
31 |
% |
Oil
(bbl) |
$ |
48.82 |
|
|
$ |
40.48 |
|
|
|
21 |
% |
|
$ |
49.16 |
|
|
$ |
37.99 |
|
|
|
29 |
% |
Gas equivalent (mcfe)
(b) |
$ |
2.88 |
|
|
$ |
2.50 |
|
|
|
15 |
% |
|
$ |
3.04 |
|
|
$ |
2.52 |
|
|
|
21 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices,
including cash-settled hedges and derivatives: (d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (mcf) |
$ |
1.74 |
|
|
$ |
1.36 |
|
|
|
28 |
% |
|
$ |
1.97 |
|
|
$ |
1.48 |
|
|
|
33 |
% |
NGL
(bbl) |
$ |
6.88 |
|
|
$ |
5.67 |
|
|
|
21 |
% |
|
$ |
7.44 |
|
|
$ |
5.24 |
|
|
|
42 |
% |
Oil
(bbl) |
$ |
48.82 |
|
|
$ |
40.48 |
|
|
|
21 |
% |
|
$ |
49.16 |
|
|
$ |
37.99 |
|
|
|
29 |
% |
Gas equivalent (mcfe)
(b) |
$ |
1.80 |
|
|
$ |
1.44 |
|
|
|
25 |
% |
|
$ |
1.98 |
|
|
$ |
1.49 |
|
|
|
33 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation,
gathering and compression expense per mcfe |
$ |
1.08 |
|
|
$ |
1.06 |
|
|
|
2 |
% |
|
$ |
1.05 |
|
|
$ |
1.03 |
|
|
|
2 |
% |
(a) Represents volumes sold regardless of when
produced.(b) Oil and NGLs are converted at the rate of one
barrel equals six mcfe based upon the approximate relative energy
content of oil to natural gas, which is not necessarily indicative
of the relationship of oil and natural gas prices.(c)
Excluding third party transportation, gathering and
compression costs.(d) Net of transportation, gathering and
compression costs.
RANGE RESOURCES CORPORATION |
|
|
|
|
|
RECONCILIATION OF INCOME BEFORE INCOME
TAXESAS REPORTED TO INCOME BEFORE INCOME TAXES
EXCLUDING CERTAIN ITEMS, a non-GAAP measure |
|
|
(Unaudited, in
thousands, except per share data) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months EndedJune 30, |
|
|
Six Months EndedJune 30, |
|
|
|
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before
income taxes, as reported |
$ |
127,201 |
|
|
$ |
(354,424 |
) |
|
$ |
409,707 |
|
|
$ |
(490,172 |
) |
|
Adjustment for certain
special items: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Gain)
loss on sale of assets |
|
(807 |
) |
|
|
3,304 |
|
|
|
(23,407 |
) |
|
|
4,947 |
|
|
Loss
(gain) on ARO settlements |
|
40 |
|
|
|
6 |
|
|
|
40 |
|
|
|
8 |
|
|
Change in
fair value related to derivatives prior to settlement |
|
(107,809 |
) |
|
|
260,876 |
|
|
|
(277,547 |
) |
|
|
283,434 |
|
|
Abandonment and impairment of unproved properties |
|
5,193 |
|
|
|
7,059 |
|
|
|
9,613 |
|
|
|
17,687 |
|
|
Impairment of proved property |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
43,040 |
|
|
Memorial
merger expenses |
|
— |
|
|
|
2,621 |
|
|
|
— |
|
|
|
2,621 |
|
|
Lawsuit
settlements |
|
540 |
|
|
|
403 |
|
|
|
1,163 |
|
|
|
1,324 |
|
|
Termination costs |
|
(50 |
) |
|
|
5 |
|
|
|
2,400 |
|
|
|
167 |
|
|
Termination costs – non-cash stock-based compensation |
|
(46 |
) |
|
|
— |
|
|
|
1,696 |
|
|
|
— |
|
|
Brokered
natural gas and marketing – non-cash stock-based compensation |
|
388 |
|
|
|
378 |
|
|
|
651 |
|
|
|
894 |
|
|
Direct
operating – non-cash stock-based compensation |
|
522 |
|
|
|
696 |
|
|
|
1,046 |
|
|
|
1,284 |
|
|
Exploration expenses – non-cash stock-based compensation |
|
528 |
|
|
|
371 |
|
|
|
1,035 |
|
|
|
1,061 |
|
|
General
& administrative – non-cash stock-based compensation |
|
14,279 |
|
|
|
15,443 |
|
|
|
25,197 |
|
|
|
26,556 |
|
|
Deferred
compensation plan – non-cash adjustment |
|
(14,466 |
) |
|
|
25,746 |
|
|
|
(27,635 |
) |
|
|
41,802 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before
income taxes, as adjusted |
|
25,513 |
|
|
|
(37,516 |
) |
|
|
123,959 |
|
|
|
(65,347 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense, as
adjusted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
Deferred
(a) |
|
9,622 |
|
|
|
(14,269 |
) |
|
|
47,250 |
|
|
|
(24,966 |
) |
|
Net income (loss)
excluding certain items, a non-GAAP measure |
$ |
15,891 |
|
|
$ |
(23,247 |
) |
|
$ |
76,709 |
|
|
$ |
(40,381 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-GAAP income per
common share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
$ |
0.06 |
|
|
$ |
(0.14 |
) |
|
$ |
0.31 |
|
|
$ |
(0.24 |
) |
|
Diluted |
$ |
0.06 |
|
|
$ |
(0.14 |
) |
|
$ |
0.31 |
|
|
$ |
(0.24 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-GAAP diluted shares
outstanding, if dilutive |
|
245,335 |
|
|
|
167,621 |
|
|
|
245,242 |
|
|
|
167,098 |
|
|
(a) Deferred taxes for 2017 and 2016 are estimated to be
approximately 38%.
|
|
RANGE RESOURCES CORPORATION |
|
|
|
HEDGING POSITION AS OF JULY 24, 2017 |
|
(Unaudited) – |
|
|
|
|
|
|
Daily Volume |
|
|
|
Hedge Price |
|
|
Gas 1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3Q 2017 Swaps |
|
|
|
841,196 Mmbtu |
|
|
|
$3.19 |
|
|
4Q 2017 Swaps |
|
|
|
867,935 Mmbtu |
|
|
|
$3.20 |
|
|
1Q 2018 Swaps |
|
|
|
1,020,000 Mmbtu |
|
|
|
$3.43 |
|
|
2Q-4Q 2018 Swaps2 |
|
|
|
260,000 Mmbtu |
|
|
|
$2.98 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3Q 2017 Collars |
|
|
|
122,609 Mmbtu |
|
|
|
$3.45 x $4.11 |
|
|
4Q 2017 Collars |
|
|
|
122,609 Mmbtu |
|
|
|
$3.45 x $4.11 |
|
|
1Q 2018 Collars |
|
|
|
60,000
Mmbtu |
|
|
|
$3.40 x $3.76 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3Q 2017 Puts |
|
|
|
185,870 Mmbtu |
|
|
|
$3.50 ($0.32) 3 |
|
|
4Q 2017
Puts |
|
|
|
185,870 Mmbtu |
|
|
|
$3.50 ($0.32) 3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3Q 2017 Swaps |
|
|
|
8,761
bbls |
|
|
|
$56.38 |
|
|
4Q 2017 Swaps |
|
|
|
8,761
bbls |
|
|
|
$56.38 |
|
|
2018 Swaps |
|
|
|
5,250
bbls |
|
|
|
$53.20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
Swaps |
|
|
|
500 bbls |
|
|
|
$51.75 |
|
|
|
|
|
|
|
|
|
|
|
|
|
C2
Ethane |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3Q 2017 Swaps |
|
|
|
3,000
bbls |
|
|
|
$0.27/gallon |
|
|
4Q 2017 Swaps |
|
|
|
3,000
bbls |
|
|
|
$0.27/gallon |
|
|
1H 2018 Swaps |
|
|
|
250
bbls |
|
|
|
$0.29/gallon |
|
|
|
|
|
|
|
|
|
|
|
|
|
C3
Propane |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3Q 2017 Swaps |
|
|
|
13,826
bbls |
|
|
|
$0.56/gallon |
|
|
4Q 2017 Swaps |
|
|
|
14,076
bbls |
|
|
|
$0.56/gallon |
|
|
2018 Swaps |
|
|
|
7,199
bbls |
|
|
|
$0.61/gallon |
|
|
|
|
|
|
|
|
|
|
|
|
|
C4 Normal
Butane |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3Q 2017 Swaps |
|
|
|
7,750
bbls |
|
|
|
$0.74/gallon |
|
|
4Q 2017 Swaps |
|
|
|
8,000
bbls |
|
|
|
$0.75/gallon |
|
|
2018 Swaps |
|
|
|
4,250
bbls |
|
|
|
$0.81/gallon |
|
|
|
|
|
|
|
|
|
|
|
|
|
C5 Natural
Gasoline |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3Q 2017 Swaps |
|
|
|
5,500
bbls |
|
|
|
$1.07/gallon |
|
|
4Q 2017 Swaps |
|
|
|
5,500
bbls |
|
|
|
$1.07/gallon |
|
|
2018 Swaps |
|
|
|
1,500
bbls |
|
|
|
$1.19/gallon |
|
(1) Range has deferred calls at a strike of $3.70 for 2H17.
Total volume of 4,300,000 Mmbtu with a deferred premium price of
$0.27 paid to Range(2) Includes swaps of 40,000 Mmbtu per day
at $3.05 which could be extended into 2019 (3) Notes deferred
premium on puts
NOTE: SEE WEBSITE FOR OTHER
SUPPLEMENTAL INFORMATION FOR THE PERIODS
Investor Contacts:
Laith Sando, Vice President – Investor Relations
817-869-4267
lsando@rangeresources.com
David Amend, Investor Relations Manager
817-869-4266
damend@rangeresources.com
Michael Freeman, Senior Financial Analyst
817-869-4264
mfreeman@rangeresources.com
Josh Stevens, Financial Analyst
817-869-1564
jrstevens@rangeresources.com
Media Contact:
Michael Mackin, Director of Public Affairs
724-873-3224
mmackin@rangeresources.com
www.rangeresources.com
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