RANGE RESOURCES CORPORATION (NYSE:RRC) today
announced its 2016 financial results and 2017 capital spending
plan.
Highlights –
- Record average daily production of 1.854 Bcfe during the fourth
quarter
- 2017 capital budget set at $1.15 billion, projected to provide
33-35% year-over-year growth in 2017 and approximately 20% organic
growth in 2018
- North Louisiana well costs reduced to $7.7 million per well
from $8.7 million previously
- Fourth quarter 2016 unhedged cash margins improved by over four
times to $0.97 per mcfe, compared to $0.22 per mcfe in fourth
quarter 2015
- Reserve replacement of 292% at $0.34 per mcfe drill-bit
development cost for 2016
Commenting, Jeff Ventura, the Company’s CEO
said, “2016 was a significant year for Range, as we completed the
acquisition of Memorial Resource Development in September,
providing Range operational and geographic diversity with wells
that rival our prolific Marcellus wells. In addition, we are
beginning to see the advantages of a diversified marketing
portfolio, as prices are expected to improve for all products in
2017, driving higher margins and a peer-leading recycle
ratio. Higher expected margins and cash flow provide us the
opportunity to increase our capital budget to $1.15 billion in
2017, after two consecutive years of declining capital
spending. This increased activity in 2017 results in solid
growth this year, but also positions us well for 2018 and
beyond. With thousands of future locations in our core
inventory and talented operational, technical and marketing teams,
Range is well-positioned to drive shareholder value for years to
come.”
Capital Spending Plans
Range has set its 2017 capital spending budget
at $1.15 billion. Approximately two-thirds of the capital budget
will be allocated to the Marcellus and one-third to North
Louisiana. The budget includes projected service cost
increases in 2017, which are expected to be minimal in the
Company’s areas of operation. In the Marcellus, approximately
80% of activity will be directed towards liquids-rich drilling,
which has a number of advantages. Range’s liquids-rich
acreage has an extensive inventory of existing pads that reduce
capital costs and gathering expense. The acreage is also in
close proximity to capacity for both existing and expected NGL and
natural gas takeaway projects, improving netback pricing.
Lastly, recent improvements in NGL pricing has bolstered expected
drilling returns. Despite shifting capital towards the
liquids-rich area, the Company still expects production of
approximately 2.07 Bcfe per day in 2017, which equates to absolute
growth of 33% to 35% year-over-year. Capital spending in 2017
will also contribute towards production growth of approximately 20%
in 2018, expected to be at or near cash flow, assuming a natural
gas price of $3.25 per mcf and an oil price of $60.00 per
barrel.
The 2017 capital budget includes approximately
$1.07 billion for drilling and recompletions (93% of the total),
$44 million for leasehold, $22 million for seismic, and $18 million
for pipelines, facilities and other. The budget includes 118
wells expected to be brought on line during the year in the
Marcellus and 56 wells in North Louisiana. In the Marcellus,
approximately one third of the wells are planned to be drilled from
existing pads in 2017.
Fourth quarter 2016 drilling expenditures of
$195 million funded the drilling of 22 (18.9 net) wells.
Drilling expenditures for the year totaled $535 million, and Range
drilled 108 (101.9 net) wells during the year. A 100% success
rate was achieved. In addition, during 2016, $33 million was
spent on acreage purchases, $4 million on gas gathering systems and
$30 million on exploration expense. The capital
expenditure amounts include North Louisiana expenditures incurred
since closing of the merger on September 16, 2016. Drill-bit
only finding cost averaged $0.34 per mcfe, including pricing and
performance revisions with a reserve replacement ratio of 292%.
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.
Fourth Quarter 2016
GAAP revenues for the fourth quarter of 2016
totaled $254 million (38% decrease compared to fourth quarter
2015), GAAP net cash provided from operating activities including
changes in working capital was $185 million (a 5% increase as
compared to fourth quarter 2015) and GAAP earnings were a loss of
$161 million ($0.66 per diluted share) versus a loss of $322
million ($1.93 per diluted share) in the prior-year quarter.
Fourth quarter 2016 results included a $470,000 gain on sale of
assets, while 2015 included a loss of $409 million. Fourth
quarter 2016 also included $250 million in derivative losses due to
increased commodity prices, compared to a $126 million gain in
2015. An $88 million impairment of proved property was also
recorded in 2015.
Non-GAAP revenues for fourth quarter 2016
totaled $590 million (30% increase compared to fourth quarter 2015)
and cash flow from operations before changes in working capital, a
non-GAAP measure, reached $254 million, compared to $204 million in
2015. Adjusted net income comparable to analysts’ estimates,
a non-GAAP measure, was $56 million ($0.23 per diluted share)
compared to $42 million ($0.25 per diluted share) for the fourth
quarter 2015. The Company’s total unit costs were lower than
the previous year quarter, with decreases in all categories, except
general & administrative and transportation, gathering,
processing & compression. General & administrative
expenses were higher due to non-recurring land administrative
expenses while increased transportation expenses are offset by
higher realized prices, as products are moved to more favorable
markets.
Expenses |
|
4Q 2016 (per
mcfe) |
|
4Q 2015(per
mcfe) |
|
|
Increase(Decrease) |
|
|
|
|
|
|
|
|
|
Direct operating |
|
$ |
0.17 |
|
$ |
0.22 |
|
|
(23 |
%) |
|
Transportation,
gathering, processing and compression |
|
|
0.96 |
|
|
0.85 |
|
|
13 |
% |
|
Production and ad
valorem taxes |
|
|
0.04 |
|
|
0.06 |
|
|
(33 |
%) |
|
General and
administrative |
|
|
0.26 |
|
|
0.22 |
|
|
18 |
% |
|
Interest expense |
|
|
0.27 |
|
|
0.31 |
|
|
(13 |
%) |
|
Total
cash unit costs |
|
|
1.70 |
|
|
1.66 |
|
|
2 |
% |
|
Depletion, depreciation
and amortization |
|
|
0.88 |
|
|
0.97 |
|
|
(9 |
%) |
|
Total
unit costs |
|
$ |
2.58 |
|
$ |
2.63 |
|
|
(2 |
%) |
|
|
|
|
|
|
|
|
|
|
Fourth quarter 2016 natural gas, NGLs and oil
price realizations (including the impact of cash-settled hedges and
derivative settlements which correspond to analysts’ estimates)
averaged $3.20 per mcfe, a 1% decrease from the prior-year
quarter. 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 fourth
quarter 2016 were: natural gas – 1,244 Mmcf per day ($2.93
per mcf), NGLs – 89,628 barrels per day ($17.20 per barrel) and
crude oil and condensate – 12,005 barrels per day ($61.30 per
barrel).
- The average Company natural gas price differential including
the impact of basis hedges for the fourth quarter was ($0.37) per
mcf, which is unchanged from the prior year. The fourth
quarter average natural gas price, before all hedging settlements,
increased to $2.62 per mcf as compared to $1.90 per mcf in the
prior year. NYMEX natural gas financial hedges increased
realizations $0.31 per mcf in the fourth quarter of 2016.
- Pre-hedge NGL realizations improved to 29% of West Texas
Intermediate (“WTI”) in fourth quarter 2016, compared to 22% of WTI
in the previous year. Total NGL pricing per barrel including
ethane and processing expenses after realized cash-settled hedging
improved to $17.20 for the fourth quarter compared to $11.23 per
barrel in the prior year. Hedging increased NGL prices by
$2.70 per barrel in the fourth quarter compared to $2.12 per barrel
in the prior year.
- Crude oil and condensate price realizations, before realized
hedges, for the fourth quarter averaged $44.61 per barrel, or $4.66
below WTI, compared to $13.52 below WTI in the prior year.
Hedging added $16.69 per barrel compared to hedge gains of
$50.92 in the prior year.
Full Year 2016
GAAP revenues for 2016 totaled $1.1 billion (31%
decrease compared to 2015), GAAP net cash provided from operating
activities including changes in working capital was $387 million,
compared to $691 million in 2015, and GAAP earnings were a loss of
$521 million ($2.75 per diluted share) versus a loss of $714
million ($4.29 per diluted share) in 2015. Full year 2016
results included a loss of $7 million from asset sales compared to
a loss of $407 million in 2015, $261 million in derivative losses
due to increases in future commodity prices compared to a $416
million gain in the prior year and a $43 million impairment of
proved property compared to a $590 million impairment of a
non-Marcellus property in the prior year.
Non-GAAP revenues for 2016 totaled $1.7 billion,
unchanged from 2015 and cash flow from operations before changes in
working capital, a non-GAAP measure, was $569 million, compared to
$740 million in 2015. Adjusted net income comparable to
analysts’ estimates, a non-GAAP measure, was $4.9 million ($0.03
per diluted share), compared to $80 million ($0.48 per diluted
share) in 2015. The Company’s cost structure continued to
improve as total unit costs decreased by $0.17 per mcfe, or 6%,
compared to the prior year, as shown below.
Expenses |
|
Full Year2016(per
mcfe) |
|
Full Year2015 (per
mcfe) |
|
|
Increase(Decrease) |
|
|
|
|
|
|
|
|
Direct operating |
|
$ |
0.17 |
|
$ |
0.26 |
|
|
(35 |
%) |
Transportation,
gathering, processing and compression |
|
|
1.00 |
|
|
0.78 |
|
|
28 |
% |
Production and ad
valorem taxes |
|
|
0.05 |
|
|
0.07 |
|
|
(29 |
%) |
General and
administrative |
|
|
0.23 |
|
|
0.27 |
|
|
(15 |
%) |
Interest expense |
|
|
0.30 |
|
|
0.33 |
|
|
(9 |
%) |
Total
cash unit costs |
|
|
1.75 |
|
|
1.71 |
|
|
2 |
% |
Depletion, depreciation
and amortization |
|
|
0.93 |
|
|
1.14 |
|
|
(18 |
%) |
Total
unit costs |
|
$ |
2.68 |
|
$ |
2.85 |
|
|
(6 |
%) |
|
|
|
|
|
|
|
|
|
|
|
The Company announced its full year 2016 natural
gas, NGLs and oil price realizations (including the impact of
cash-settled hedges and derivative settlements which correspond to
analysts’ estimates), which averaged $2.74 per mcfe, a 14% decrease
from the prior year. 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 2016
were: natural gas – 1,027 Mmcf per day ($2.68 per mcf), NGLs
– 76,026 barrels per day ($13.16 per barrel) and crude oil and
condensate – 9,861 barrels per day ($47.82 per barrel).
- The 2016 average Company natural gas price differential
including the impact of basis hedging improved to ($0.45) per mcf
compared to ($0.52) per mcf in the prior year. The 2016
average natural gas price, before all hedging settlements,
decreased to $2.06 per mcf as compared to $2.13 per mcf in the
prior year. NYMEX natural gas financial hedges increased
realizations $0.61 per mcf for 2016.
- Pre-hedge NGL realizations improved to 26% of WTI in 2016,
compared to 18% of WTI in 2015. Total NGL pricing per barrel
including ethane and processing expenses after realized
cash-settled hedging was $13.15 per barrel compared to $10.73 in
the prior year. Hedging increased NGL prices by $1.71 per
barrel in 2016 compared to $2.06 in the prior year.
- Crude oil and condensate price realizations, before hedges, for
the year averaged $34.60 per barrel, or $9.09 below WTI, compared
to $14.93 below WTI in the prior year. Hedging added
$13.22 per barrel in 2016, compared to hedge gains of $37.00 per
barrel in the prior year.
Operational Discussion
Range has updated its investor presentation with
new economic calculations and type curves for the Marcellus and
North Louisiana. Please see www.rangeresources.com under the
Investors tab, “Company Presentations” area, for the presentation
entitled, “Company Presentation – February 22, 2017”
The table below summarizes the 2016 activity and
estimates for 2017 regarding the number of wells to sales, average
lateral lengths, well costs, EURs by area and Range’s current net
acreage for each area. Consistent with the prior year,
updated type curves reflect expected flow restrictions that result
from infrastructure and facility design constraints. As a
result, early production from prolific wells is often constrained,
resulting in flatter decline curves, and is reflected in the type
curves. As seen in the presentation slides, Marcellus wells
turned in line (“TIL”) over the past three years continue to
perform in line with type curve expectations. These results
demonstrate the quality of acreage as the Company continues
development across its core position in southwest
Pennsylvania. Similar data is expected to be provided for
North Louisiana drilling results going forward.
|
|
Wells TILin 2016 |
|
Average 2016Lateral Length |
|
Planned Wells TILin 2017 |
|
Expected Average2017 Lateral Length |
|
|
|
|
|
SW PA Super-Rich |
|
14 |
|
5,100
ft. |
|
35 |
|
8,500
ft. |
SW PA Wet |
|
30 |
|
6,400
ft. |
|
56 |
|
8,300
ft. |
SW PA Dry |
|
46 |
|
6,900
ft. |
|
25 |
|
8,850
ft. |
NE PA Dry |
|
19 |
|
5,700
ft. |
|
2 |
|
6,400
ft. |
Total
Marcellus |
|
109 |
|
|
|
118 |
|
|
Upper Red |
|
— |
|
|
|
34 |
|
7,500
ft. |
Lower Red |
|
— |
|
|
|
13 |
|
7,500
ft. |
Pink |
|
— |
|
|
|
6 |
|
|
Expansion area |
|
3 |
|
|
|
3 |
|
|
Total
N. LA |
|
3 |
|
|
|
56 |
|
|
Total |
|
112 |
|
|
|
174 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected 2017Well Costs |
|
Projected EURsfor 2017 Wells |
|
Net Acreage by Area(Marcellus only) |
|
|
|
|
|
|
|
|
SW PA Super-Rich |
|
$7.3 million |
|
20.4 Bcfe |
|
110,000 |
|
|
SW PA Wet |
|
$6.8 million |
|
24.6 Bcfe |
|
225,000 |
|
|
SW PA Dry |
|
$6.1 million |
|
22.3 Bcf |
|
180,000 |
|
|
NE PA Dry |
|
$5.0 million |
|
16.0 Bcf |
|
95,000 |
|
|
Total
Marcellus |
|
|
|
|
|
610,000 |
|
|
Upper Red |
|
$7.7 million |
|
17.5
Bcfe |
|
|
|
|
Lower Red |
|
$7.7 million |
|
11.8
Bcfe |
|
|
|
|
Total
N. LA |
|
|
|
|
|
220,000 |
|
|
Total |
|
|
|
|
|
830,000 |
|
|
|
|
|
|
|
|
|
|
|
Marcellus Shale
Production for the fourth quarter of 2016
averaged approximately 1,419 net Mmcfe per day for both Marcellus
Shale divisions, an 11% increase over the prior year. The
Southern Marcellus Shale Division averaged 1,235 net Mmcfe per day
during the quarter, a 20% increase over the prior year. The
Northern Marcellus Shale Division averaged 184 net Mmcf per day
during the quarter, a 25% decrease over the prior year, or a 16%
decrease over the prior year when adjusted for asset sales.
Southern Marcellus Shale
The Southern Marcellus Shale division brought on
line ten wells in the fourth quarter, one in the super-rich area,
four in the wet area and five in the dry area. The operated
rig count of five has stayed consistent throughout most of the
second half of 2016, with three horizontal rigs and two air
rigs.
The team continues to look for ways to reduce
costs and increase recoveries. Several recent examples are
shown below, which have continued to drive lower normalized well
costs and reductions in operating costs per mcfe.
- Lateral lengths averaged 6,500 feet in 2016, compared to 6,100
feet in 2015, with projected lateral lengths in 2017 expected to
average over 8,000 feet
- Reduced water handling costs in 2016 by over $30 million
compared to 2015
- Increased lateral feet drilled per day by 40% compared to the
previous year
- Reduced average completion costs per lateral foot by 14%
compared to the previous year
- Managed service costs through better utilization rates and
long-term vendor relationships
A recent example of what we expect when going
back to core areas with longer laterals is a four well pad in the
wet area brought on line in the fourth quarter, with an average
9,265 lateral length with 46 stages per well. The average
peak 24 hour production rate to sales, under constrained conditions
was 35.1 Mmcfe per day per well, roughly twice the average rate of
the offset pads. This is a result of refined completion
designs, improved landing and longer laterals. On a
normalized basis, average cost per well is $651,000 per 1,000
lateral foot with average EUR per well of 3.9 Bcfe per 1,000
lateral foot. On an absolute basis, these wells represent a
47% improvement in recoveries, with an 11% reduction in cost from
the average shown on page 35 in the latest investor presentation,
with many additional locations expected to produce similar
results.
North Louisiana
Production for the division in the fourth
quarter of 2016, the first full quarter since the Memorial
acquisition closing on September 16, 2016, averaged approximately
399 net Mmcfe per day, consisting of 294 Mmcf per day of gas,
13,461 barrels of NGLs per day and 3,998 barrels of condensate per
day.
Since acquiring the assets, significant progress
has been made operationally, including integration of personnel,
information systems, communications systems and facilities.
As mentioned on our third quarter conference call, Range has
a new drilling team with extensive experience in high-pressure,
high-temperature drilling conditions, including experience in the
Vernon field. The team has been able to implement significant
improvements to date. As a result, total well costs for a
typical 7,500 foot lateral well drilled in Terryville have declined
from $8.7 million to $7.7 million in just the past five months
thereby improving returns and potentially increasing location
count. In addition, these cost reductions have occurred while
staying within the targeted zone, which has the potential to
increase recoveries. The new targeting interval also has been
reduced to approximately 30 feet, compared to 90 to 100 feet
previously. Updated economics for Upper and Lower Red areas
can be found in the Company presentation on slides 40, and 42,
showing attractive returns at current strip pricing.
As reported in late January, three wells were
drilled and completed in the extension area prior to
year-end. The wells were drilled on the north, east and west
sides of the Vernon field. Based on logs and
cores, the wells to the east and west of Vernon field appear to be
structurally similar to Vernon, with multiple, stacked pay zones,
and as expected, the over pressured Lower Cotton Valley section
thickens when moving south from Terryville. The eastern and
western wells each encountered six pay zones with total gas in
place of approximately 400 Bcf per square mile, approximately 2.5
times Terryville. Initial production results indicate that
each well is expected to have a normalized gas EUR that is in line
with Terryville Upper and Lower Red wells. With these
encouraging results, Range will continue to analyze well data,
observe production characteristics with plans to drill additional
extension wells in 2017.
Marketing and
Transportation
Range’s overall marketing strategy for many
years has been to assemble a diversified low-cost transportation
portfolio. Recent developments are proving this to be a good
strategy, with net pricing expected to improve on all products in
2017.
Natural gas pricing improved in the fourth
quarter, with a full quarter of North Louisiana production and the
addition of Spectra’s Gulf Markets project going in-service in
early October 2016. The project allows Range to transport
150,000 Mmbtu per day from southwest Pennsylvania to the Gulf
Coast, providing a significant improvement to differentials.
Additionally, we have received favorable news
regarding FERC authorizations on all remaining Appalachian takeaway
projects on which Range holds capacity. Spectra’s Adair
Southwest project received its final FERC Certificate in the fourth
quarter providing incremental transportation out of the Appalachian
basin starting in late 2017. TransCanada’s Leach and Rayne
Express projects received their final FERC Certificates in January,
with a projected in-service date in late 2017 as well. The
combined capacity from these projects for Range is an additional
400,000 Mmbtu per day from the Appalachian Basin to the Gulf Coast,
further improving our expected basis differentials. In
addition, in early February, FERC approved Energy Transfer’s Rover
project. Range has 400,000 Mmbtu/day capacity on the project,
with half delivered to Midwest/Canadian markets and half to the
Gulf Coast. When combining this capacity with Range’s North
Louisiana production, which receives near NYMEX pricing, Range
expects its corporate gas differential to improve to approximately
$0.30 below NYMEX in 2017. In calculating the differentials,
Range assumed only 400,000 Mmbtu per day of capacity would be
in-service late 2017.
Range’s gathering and processing costs per mcfe
are expected to improve in coming years. In North Louisiana, Range
acquired approximately double the processing capacity currently
being utilized when the assets were acquired. Range will
continue to focus the majority of its activities in the core of the
Terryville area which will permit better utilization of our
processing commitments in 2017, thereby reducing our minimum volume
commitment expenses on a per mcfe basis. In the Marcellus,
Range has largely captured the resource and is now going back to
existing pads and areas of existing infrastructure, resulting in a
downward trend in the Company’s gathering rates per mcfe.
NGL pricing has also improved recently on better
domestic market fundamentals and the Company’s strong portfolio of
domestic and international sales. As a result, Range’s
calculated NGL prices (including ethane and processing costs) for
2017 increased to a range of 28% to 30% of WTI, based on current
strip pricing. This approximate 2% increase in
realizations would increase pre-hedge NGL revenue by approximately
$40 million for the year. Condensate prices have
improved relative to WTI as well. Condensate differentials in
the fourth quarter improved to less than $5.00 per barrel, driven
largely by the improvement in realizations gained through the
addition of Louisiana sales and new Marcellus condensate sales
agreements announced in the third quarter. Based on these
results, guidance for condensate differentials in 2017 has improved
to $5.00 - $6.00 below WTI.
Financial Position and
Liquidity
At December 31, 2016, Range had total debt
outstanding of $3.81 billion, before debt issuance costs,
consisting of $2.88 billion in senior notes, $882 million in bank
debt and $49 million in senior subordinated notes. Net debt
outstanding, after unamortized debt issuance costs and premiums,
equals $3.78 billion.
At December 31, 2016, Range’s bank facility had
a borrowing base of $3.0 billion, and bank commitments of $2.0
billion, with an outstanding balance of $882 million and undrawn
letters of credit of $261 million, leaving $850 million of
borrowing capacity available under the commitment amount.
Guidance – 2017
Production per day Guidance
Production for the first quarter of 2017 is
expected to be approximately 1.92 Bcfe per day with 30% to 32%
liquids.
Production for the full year 2017 is expected to
average approximately 2.07 Bcfe per day. This equates to a
year-over-year growth rate of 33% to 35%.
1Q 2017 Expense Guidance
Direct operating
expense: |
$0.18 - $0.19 per
mcfe |
Transportation,
gathering, processing and compression expense: |
$1.00 - $1.04 per
mcfe |
Production tax
expense: |
$0.05 - $0.07 per
mcfe |
Exploration
expense: |
$12.0 - $13.0
million |
Unproved property
impairment expense: |
$6.0 - $8.0
million |
G&A expense: |
$0.23 - $0.25 per
mcfe |
Interest expense: |
$0.26 - $0.28 per
mcfe |
DD&A expense: |
$0.88 - $0.90 per
mcfe |
Net brokered gas
marketing expense: |
~$2.0 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 2017 natural gas production
hedged at a weighted average floor price of $3.22 per mcf.
Similarly, Range has hedged over 60% of its 2017 projected crude
oil production at a floor price of $55.81 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 Marcellus and other basis
differentials to limit volatility between NYMEX and regional
prices. The fair value of the basis hedges as of December 31,
2016 was a gain of $11.8 million, compared to a gain of $5.5
million at December 31, 2015.
Conference Call Information
A conference call to review the financial
results is scheduled on Thursday, February 23 at 9:00 a.m. ET. To
participate in the call, please dial 866-900-7525 and provide
conference code 48391940 about 10 minutes prior to the scheduled
start time.
A simultaneous webcast of the call may be
accessed at www.rangeresources.com. The webcast will be archived
for replay on the Company's website until March 23.
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
income statement. The Company believes that it is important
to furnish a table reflecting the details of the various components
of each income statement line to better inform the reader of the
details of each amount and provide a summary of the realized
cash-settled amounts and third-party transportation, gathering,
processing and compression expense which 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 Statements of Operations to better inform the reader of the
details of each amount, the changes between periods and the effect
on its financial results.
Range has disclosed two primary metrics in this
release to measure our ability to establish a long-term trend of
adding reserves at a reasonable cost – a reserve replacement ratio
and finding and development cost per unit. The reserve
replacement ratio is an indicator of our ability to replace annual
production volumes and grow our reserves. It is important to
economically find and develop new reserves that will offset
produced volumes and provide for future production given the
inherent decline of hydrocarbon reserves as they are produced. We
believe the ability to develop a competitive advantage over other
natural gas and oil companies is dependent on adding reserves in
our core areas at lower costs than our competition. The
reserve replacement ratio is calculated by dividing production for
the year into the total of proved reserve extensions, discoveries
and additions and proved reserve revisions, excluding PUD removals
based on the SEC 5-year rule.
Finding and development cost per unit is a
non-GAAP metric used in the exploration and production industry by
companies, investors and analysts. The calculations presented by
the Company are based on estimated and unaudited costs incurred
excluding asset retirement obligations and divided by proved
reserve additions (extensions, discoveries and additions) adjusted
for the changes in proved reserves for acquisitions, performance
revisions and/or price revisions and including or excluding acreage
costs as stated in each instance in the release. Drill-bit
development cost per mcfe is based on estimated and unaudited
drilling, development and exploration costs incurred divided by the
total of reserve additions, performance and price revisions.
These calculations do not include the future development costs
required for the development of proved undeveloped reserves. The
SEC method of computing finding costs contains additional cost
components and results in a higher number. A reconciliation
of the two methods is shown on our website at
www.rangeresources.com.
The reserve replacement ratio and finding and
development cost per unit are statistical indicators that have
limitations, including their predictive and comparative
value. As an annual measure, the reserve replacement ratio
can be limited because it may vary widely based on the extent and
timing of new discoveries and the varying effects of changes in
prices and well performance. In addition, since the reserve
replacement ratio and finding and development cost per unit do not
consider the cost or timing of future production of new reserves,
such measures may not be an adequate measure of value
creation. These reserves metrics may not be comparable to
similarly titled measurements used by other companies.
RANGE RESOURCES CORPORATION
(NYSE:RRC) is a leading U.S. independent oil and natural gas
producer with operations focused in stacked-pay projects in
the Appalachian Basin and North Louisiana. The Company pursues
an organic growth strategy targeting high return, low-cost projects
within its large inventory of low risk development drilling
opportunities. The Company is headquartered in Fort Worth,
Texas. More information about Range can be found at
www.rangeresources.com.
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 merger
integration, 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.
2017-04SOURCE: Range Resources
Corporation
|
|
RANGE RESOURCES CORPORATION |
|
STATEMENTS OF
OPERATIONS |
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Based on GAAP reported
earnings with additional |
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details of items
included in each line in Form 10-K |
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(Audited, in thousands,
except per share data) |
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Three Months Ended December 31, |
|
Twelve Months Ended December 31, |
|
|
2016 |
|
|
|
2015 |
|
|
|
% |
|
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|
2016 |
|
|
|
2015 |
|
|
|
% |
|
|
|
|
|
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|
|
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Revenues and other
income: |
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|
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|
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|
|
|
|
|
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|
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|
|
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|
Natural
gas, NGLs and oil sales (a) |
$ |
458,645 |
|
|
$ |
254,043 |
|
|
|
|
|
|
$ |
1,197,215 |
|
|
$ |
1,089,644 |
|
|
|
|
|
Derivative fair value (loss)/income |
|
(250,057 |
) |
|
|
126,312 |
|
|
|
|
|
|
|
(261,391 |
) |
|
|
416,364 |
|
|
|
|
|
Brokered
natural gas, marketing and other (b) |
|
44,774 |
|
|
|
30,100 |
|
|
|
|
|
|
|
163,219 |
|
|
|
90,922 |
|
|
|
|
|
ARO
settlement gain (loss) (b) |
|
54 |
|
|
|
80 |
|
|
|
|
|
|
|
40 |
|
|
|
103 |
|
|
|
|
|
Other
(b) |
|
106 |
|
|
|
192 |
|
|
|
|
|
|
|
856 |
|
|
|
1,035 |
|
|
|
|
|
Total
revenues and other income |
|
253,522 |
|
|
|
410,727 |
|
|
|
-38 |
% |
|
|
1,099,939 |
|
|
|
1,598,068 |
|
|
|
-31 |
% |
|
|
|
|
|
|
|
|
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Costs and
expenses: |
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|
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|
|
|
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|
|
|
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|
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|
|
|
|
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Direct
operating |
|
29,755 |
|
|
|
28,757 |
|
|
|
|
|
|
|
95,086 |
|
|
|
133,583 |
|
|
|
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|
Direct
operating – non-cash stock-based compensation (c) |
|
521 |
|
|
|
631 |
|
|
|
|
|
|
|
2,302 |
|
|
|
2,780 |
|
|
|
|
|
Transportation, gathering, processing and compression |
|
164,338 |
|
|
|
112,481 |
|
|
|
|
|
|
|
565,209 |
|
|
|
396,739 |
|
|
|
|
|
Production and ad valorem taxes |
|
6,790 |
|
|
|
7,354 |
|
|
|
|
|
|
|
25,443 |
|
|
|
33,860 |
|
|
|
|
|
Brokered
natural gas and marketing |
|
46,095 |
|
|
|
34,553 |
|
|
|
|
|
|
|
166,851 |
|
|
|
113,734 |
|
|
|
|
|
Brokered
natural gas and marketing – non-cash stock-based
compensation (c) |
|
376 |
|
|
|
389 |
|
|
|
|
|
|
|
1,725 |
|
|
|
2,132 |
|
|
|
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|
Exploration |
|
13,055 |
|
|
|
3,446 |
|
|
|
|
|
|
|
30,027 |
|
|
|
18,421 |
|
|
|
|
|
Exploration – non-cash stock-based compensation (c) |
|
629 |
|
|
|
814 |
|
|
|
|
|
|
|
2,298 |
|
|
|
2,985 |
|
|
|
|
|
Abandonment and impairment of unproved properties |
|
6,307 |
|
|
|
11,432 |
|
|
|
|
|
|
|
30,076 |
|
|
|
47,619 |
|
|
|
|
|
General
and administrative |
|
44,285 |
|
|
|
29,476 |
|
|
|
|
|
|
|
132,104 |
|
|
|
136,290 |
|
|
|
|
|
General
and administrative – non-cash stock-based compensation
(c) |
|
11,611 |
|
|
|
11,142 |
|
|
|
|
|
|
|
49,293 |
|
|
|
49,687 |
|
|
|
|
|
General
and administrative – lawsuit settlements |
|
1,131 |
|
|
|
1,226 |
|
|
|
|
|
|
|
2,575 |
|
|
|
3,238 |
|
|
|
|
|
General
and administrative – bad debt expense |
|
— |
|
|
|
1,700 |
|
|
|
|
|
|
|
800 |
|
|
|
2,300 |
|
|
|
|
|
General
and administrative – DEP penalty |
|
— |
|
|
|
— |
|
|
|
|
|
|
|
— |
|
|
|
2,500 |
|
|
|
|
|
Memorial
merger expenses |
|
813 |
|
|
|
— |
|
|
|
|
|
|
|
37,225 |
|
|
|
— |
|
|
|
|
|
Termination costs |
|
(822 |
) |
|
|
10,283 |
|
|
|
|
|
|
|
(519 |
) |
|
|
14,853 |
|
|
|
|
|
Termination costs – non-cash stock-based compensation (c) |
|
— |
|
|
|
(1,503 |
) |
|
|
|
|
|
|
— |
|
|
|
217 |
|
|
|
|
|
Deferred
compensation plan (d) |
|
(11,013 |
) |
|
|
(21,016 |
) |
|
|
|
|
|
|
19,153 |
|
|
|
(77,627 |
) |
|
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Interest
expense |
|
46,749 |
|
|
|
40,849 |
|
|
|
|
|
|
|
168,213 |
|
|
|
166,439 |
|
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Loss on
early extinguishment of debt |
|
— |
|
|
|
— |
|
|
|
|
|
|
|
— |
|
|
|
22,495 |
|
|
|
|
|
Depletion, depreciation and amortization |
|
149,662 |
|
|
|
127,977 |
|
|
|
|
|
|
|
524,102 |
|
|
|
581,155 |
|
|
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|
Impairment of proved properties and other assets |
|
— |
|
|
|
87,941 |
|
|
|
|
|
|
|
43,040 |
|
|
|
590,174 |
|
|
|
|
|
(Gain)
loss on sale of assets |
|
(470 |
) |
|
|
408,909 |
|
|
|
|
|
|
|
7,074 |
|
|
|
406,856 |
|
|
|
|
|
Total costs and expenses |
|
509,812 |
|
|
|
896,841 |
|
|
|
-43 |
% |
|
|
1,902,077 |
|
|
|
2,650,430 |
|
|
|
-28 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
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|
Loss before income
taxes |
|
(256,290 |
) |
|
|
(486,114 |
) |
|
|
47 |
% |
|
|
(802,138 |
) |
|
|
(1,052,362 |
) |
|
|
24 |
% |
|
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|
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|
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Income tax
benefit: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
98 |
|
|
|
29 |
|
|
|
|
|
|
|
98 |
|
|
|
29 |
|
|
|
|
|
Deferred |
|
(95,679 |
) |
|
|
(164,316 |
) |
|
|
|
|
|
|
(280,848 |
) |
|
|
(338,706 |
) |
|
|
|
|
|
|
(95,581 |
) |
|
|
(164,287 |
) |
|
|
|
|
|
|
(280,750 |
) |
|
|
(338,677 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
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|
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|
Net loss |
$ |
(160,709 |
) |
|
$ |
(321,827 |
) |
|
|
50 |
% |
|
$ |
(521,388 |
) |
|
$ |
(713,685 |
) |
|
|
27 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Net Loss Per
Common Share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
$ |
(0.66 |
) |
|
$ |
(1.93 |
) |
|
|
|
|
|
$ |
(2.75 |
) |
|
$ |
(4.29 |
) |
|
|
|
|
Diluted |
$ |
(0.66 |
) |
|
$ |
(1.93 |
) |
|
|
|
|
|
$ |
(2.75 |
) |
|
$ |
(4.29 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Weighted average common
shares outstanding, as reported: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
244,362 |
|
|
|
166,573 |
|
|
|
47 |
% |
|
|
189,868 |
|
|
|
166,389 |
|
|
|
14 |
% |
Diluted |
|
244,362 |
|
|
|
166,573 |
|
|
|
47 |
% |
|
|
189,868 |
|
|
|
166,389 |
|
|
|
14 |
% |
(a) See separate natural gas, NGLs and oil sales
information table.(b) Included in Brokered natural gas,
marketing and other revenues in the 10-K.(c) Costs associated
with stock compensation and restricted stock amortization, which
have been reflected in the categories associated with the direct
personnel costs, which are combined with the cash costs in the
10-K.(d) Reflects the change in market value of the vested
Company stock held in the deferred compensation plan.
|
|
|
|
|
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|
RANGE RESOURCES CORPORATION |
|
|
|
|
|
|
|
|
BALANCE
SHEETS |
|
|
|
|
|
|
|
(Audited, In
thousands) |
|
December 31, |
|
|
|
December 31, |
|
|
|
2016 |
|
|
|
2015 |
|
|
|
|
|
|
|
|
|
Assets |
|
|
|
|
|
|
|
Current
assets |
$ |
268,605 |
|
|
$ |
157,530 |
|
Derivative assets |
|
13,483 |
|
|
|
288,762 |
|
Goodwill |
|
1,654,292 |
|
|
|
— |
|
Natural
gas and oil properties, successful efforts method |
|
9,256,337 |
|
|
|
6,361,305 |
|
Transportation and field assets |
|
16,873 |
|
|
|
19,455 |
|
Other |
|
72,655 |
|
|
|
72,979 |
|
|
$ |
11,282,245 |
|
|
$ |
6,900,031 |
|
|
|
|
|
|
|
|
|
Liabilities and
Stockholders’ Equity |
|
|
|
|
|
|
|
Current
liabilities |
$ |
530,373 |
|
|
$ |
335,513 |
|
Asset
retirement obligations |
|
7,271 |
|
|
|
15,071 |
|
Derivative liabilities |
|
165,009 |
|
|
|
1,136 |
|
|
|
|
|
|
|
|
|
Bank
debt |
|
876,428 |
|
|
|
86,427 |
|
Senior
notes |
|
2,848,591 |
|
|
|
738,101 |
|
Senior
subordinated notes |
|
48,498 |
|
|
|
1,826,775 |
|
Total
debt |
|
3,773,517 |
|
|
|
2,651,303 |
|
|
|
|
|
|
|
|
|
Deferred
tax liability |
|
943,343 |
|
|
|
777,947 |
|
Derivative liabilities |
|
24,491 |
|
|
|
21 |
|
Deferred
compensation liability |
|
119,231 |
|
|
|
104,792 |
|
Asset
retirement obligations and other liabilities |
|
310,642 |
|
|
|
254,590 |
|
|
|
|
|
|
|
|
|
Common
stock and retained earnings |
|
5,409,577 |
|
|
|
2,761,903 |
|
Common
stock held in treasury stock |
|
(1,209 |
) |
|
|
(2,245 |
) |
Total
stockholders’ equity |
|
5,408,368 |
|
|
|
2,759,658 |
|
|
$ |
11,282,245 |
|
|
$ |
6,900,031 |
|
|
|
|
|
|
|
|
|
|
|
|
|
RECONCILIATION
OF TOTAL REVENUES AND OTHER INCOME TO TOTAL REVENUE EXCLUDING
CERTAIN ITEMS, a non-GAAP measure |
|
|
|
(Unaudited, in
thousands) |
|
|
|
|
Three Months Ended December 31, |
|
Twelve Months Ended December 31, |
|
|
2016 |
|
|
|
2015 |
|
|
|
% |
|
|
|
2016 |
|
|
|
2015 |
|
|
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues and
other income, as reported |
$ |
253,522 |
|
|
$ |
410,727 |
|
|
|
-38 |
% |
|
$ |
1,099,939 |
|
|
$ |
1,598,068 |
|
|
-31 |
% |
Adjustment for certain
special items: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
change in fair value related to derivatives prior to
settlement loss |
|
336,736 |
|
|
|
45,165 |
|
|
|
|
|
|
|
608,727 |
|
|
|
115,758 |
|
|
|
|
ARO
settlement (gain) loss |
|
(54 |
) |
|
|
(80 |
) |
|
|
|
|
|
|
(40 |
) |
|
|
(103 |
) |
|
|
|
Total revenues, as
adjusted, non-GAAP |
$ |
590,204 |
|
|
$ |
455,812 |
|
|
|
30 |
% |
|
$ |
1,708,626 |
|
|
$ |
1,713,723 |
|
|
0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RANGE RESOURCES CORPORATION |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM
OPERATING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited in
thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended December 31, |
|
|
Twelve Months Ended December 31, |
|
|
|
2016 |
|
|
|
2015 |
|
|
|
2016 |
|
|
|
2015 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
$ |
(162,771 |
) |
|
$ |
(321,827 |
) |
|
$ |
(521,388 |
) |
|
$ |
(713,685 |
) |
Adjustments to
reconcile net cash provided from continuing operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
income tax benefit |
|
(93,617 |
) |
|
|
(164,316 |
) |
|
|
(280,848 |
) |
|
|
(338,706 |
) |
Depletion, depreciation, amortization and impairment |
|
149,662 |
|
|
|
215,918 |
|
|
|
567,142 |
|
|
|
1,171,329 |
|
Exploration dry hole costs |
|
16 |
|
|
|
1 |
|
|
|
18 |
|
|
|
88 |
|
Abandonment and impairment of unproved properties |
|
6,307 |
|
|
|
11,432 |
|
|
|
30,076 |
|
|
|
47,619 |
|
Derivative fair value loss (income) |
|
250,057 |
|
|
|
(126,312 |
) |
|
|
261,391 |
|
|
|
(416,364 |
) |
Cash
settlements on derivative financial instruments that do not qualify
for hedge accounting |
|
86,679 |
|
|
|
171,477 |
|
|
|
347,336 |
|
|
|
532,122 |
|
Allowance
for bad debts |
|
— |
|
|
|
1,700 |
|
|
|
800 |
|
|
|
2,300 |
|
Amortization of deferred issuance costs, loss on extinguishment of
debt and other |
|
1,787 |
|
|
|
1,811 |
|
|
|
7,170 |
|
|
|
29,383 |
|
Deferred
and stock-based compensation |
|
1,996 |
|
|
|
(9,732 |
) |
|
|
74,685 |
|
|
|
(20,411 |
) |
(Gain)
loss on sale of assets and other |
|
(470 |
) |
|
|
408,909 |
|
|
|
7,074 |
|
|
|
406,856 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes
in working capital: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
receivable |
|
(52,571 |
) |
|
|
(14,744 |
) |
|
|
(20,586 |
) |
|
|
64,704 |
|
Inventory
and other |
|
6,996 |
|
|
|
(7,795 |
) |
|
|
6,220 |
|
|
|
(14,868 |
) |
Accounts
payable |
|
14,009 |
|
|
|
(13,039 |
) |
|
|
(27,259 |
) |
|
|
(26,197 |
) |
Accrued
liabilities and other |
|
(23,049 |
) |
|
|
22,359 |
|
|
|
(64,763 |
) |
|
|
(32,768 |
) |
Net
changes in working capital |
|
(54,615 |
) |
|
|
(13,219 |
) |
|
|
(106,388 |
) |
|
|
(9,129 |
) |
Net cash
provided from operating activities |
$ |
185,031 |
|
|
$ |
175,842 |
|
|
$ |
387,068 |
|
|
$ |
691,402 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RECONCILIATION
OF NET CASH PROVIDED FROM OPERATING ACTIVITIES, AS REPORTED, TO
CASH FLOW FROM OPERATIONS BEFORE CHANGES IN WORKING CAPITAL, a
non-GAAP measure |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited, in
thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended December 31, |
|
|
Twelve Months Ended December 31, |
|
|
|
2016 |
|
|
|
2015 |
|
|
|
2016 |
|
|
|
2015 |
|
Net cash provided from
operating activities, as reported |
$ |
185,031 |
|
|
$ |
175,842 |
|
|
$ |
387,068 |
|
|
$ |
691,402 |
|
Net
changes in working capital |
|
54,615 |
|
|
|
13,219 |
|
|
|
106,388 |
|
|
|
9,129 |
|
Exploration expense |
|
13,039 |
|
|
|
3,445 |
|
|
|
30,009 |
|
|
|
18,333 |
|
Lawsuit
settlements |
|
1,131 |
|
|
|
1,226 |
|
|
|
2,575 |
|
|
|
3,238 |
|
Cash paid
to exchange senior subordinated notes |
|
— |
|
|
|
— |
|
|
|
6,600 |
|
|
|
— |
|
Legal
contingency/DEP penalty |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
2,500 |
|
Memorial
merger expenses |
|
813 |
|
|
|
— |
|
|
|
37,225 |
|
|
|
— |
|
Termination costs |
|
(822 |
) |
|
|
10,283 |
|
|
|
(519 |
) |
|
|
14,853 |
|
Non-cash
compensation adjustment |
|
56 |
|
|
|
73 |
|
|
|
19 |
|
|
|
709 |
|
Cash flow from
operations before changes in working capital – non-GAAP
measure |
$ |
253,863 |
|
|
$ |
204,088 |
|
|
$ |
569,365 |
|
|
$ |
740,164 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ADJUSTED
WEIGHTED AVERAGE SHARES OUTSTANDING |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited, in
thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended December 31, |
|
|
Twelve Months Ended December 31, |
|
|
|
2016 |
|
|
|
2015 |
|
|
|
2016 |
|
|
|
2015 |
|
Basic: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares
outstanding |
|
247,161 |
|
|
|
169,371 |
|
|
|
192,661 |
|
|
|
169,183 |
|
Stock held by deferred
compensation plan |
|
(2,799 |
) |
|
|
(2,798 |
) |
|
|
(2,793 |
) |
|
|
(2,794 |
) |
Adjusted
basic |
|
244,362 |
|
|
|
166,573 |
|
|
|
189,868 |
|
|
|
166,389 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dilutive: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares
outstanding |
|
247,161 |
|
|
|
169,371 |
|
|
|
192,661 |
|
|
|
169,183 |
|
Dilutive stock options
under treasury method |
|
(2,799 |
) |
|
|
(2,798 |
) |
|
|
(2,793 |
) |
|
|
(2,794 |
) |
Adjusted
dilutive |
|
244,362 |
|
|
|
166,573 |
|
|
|
189,868 |
|
|
|
166,389 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, PROCESSING
AND COMPRESSION FEES, a non-GAAP measure |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited, in
thousands, except per unit data) |
|
|
|
|
|
|
Three Months Ended December 31, |
|
|
Twelve Months Ended December 31, |
|
|
|
2016 |
|
|
|
2015 |
|
|
% |
|
|
|
2016 |
|
|
|
2015 |
|
|
% |
|
Natural gas, NGLs and
oil sales components: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas sales |
$ |
289,790 |
|
|
$ |
183,576 |
|
|
|
|
|
$ |
753,888 |
|
|
$ |
773,093 |
|
|
|
|
NGLs
sales |
|
119,585 |
|
|
|
44,724 |
|
|
|
|
|
|
318,462 |
|
|
|
176,546 |
|
|
|
|
Oil
sales |
|
49,270 |
|
|
|
25,743 |
|
|
|
|
|
|
124,865 |
|
|
|
140,005 |
|
|
|
|
Total natural gas, NGL
sales, as reported |
$ |
458,645 |
|
|
$ |
254,043 |
|
|
81 |
% |
|
$ |
1,197,215 |
|
|
$ |
1,089,644 |
|
|
10 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative fair value
income (loss), as reported: |
$ |
(250,057 |
) |
|
$ |
126,312 |
|
|
|
|
|
$ |
(261,391 |
) |
|
$ |
416,364 |
|
|
|
|
Cash settlements on
derivative financial instruments – (gain) loss: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas |
|
(46,015 |
) |
|
|
(115,428 |
) |
|
|
|
|
|
(252,000 |
) |
|
|
(339,031 |
) |
|
|
|
NGLs |
|
(22,231 |
) |
|
|
(10,366 |
) |
|
|
|
|
|
(47,626 |
) |
|
|
(41,974 |
) |
|
|
|
Crude
Oil |
|
(18,433 |
) |
|
|
(45,683 |
) |
|
|
|
|
|
(47,710 |
) |
|
|
(151,117 |
) |
|
|
|
Total change in fair
value related to derivatives prior to settlement, a non-GAAP
measure |
$ |
(336,736 |
) |
|
$ |
(45,165 |
) |
|
|
|
|
$ |
(608,727 |
) |
|
$ |
(115,758 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation,
gathering, processing and compression components: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas |
$ |
114,854 |
|
|
$ |
95,849 |
|
|
|
|
|
$ |
403,209 |
|
|
$ |
343,593 |
|
|
|
|
NGLs |
|
49,484 |
|
|
|
16,632 |
|
|
|
|
|
|
162,000 |
|
|
|
53,146 |
|
|
|
|
Total transportation,
gathering, processing and compression, as reported |
$ |
164,338 |
|
|
$ |
112,481 |
|
|
|
|
|
$ |
565,209 |
|
|
$ |
396,739 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, NGL and
oil sales, including cash-settled derivatives: (c) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas sales |
$ |
335,805 |
|
|
$ |
299,004 |
|
|
|
|
|
$ |
1,005,888 |
|
|
$ |
1,112,124 |
|
|
|
|
NGLs
sales |
|
141,816 |
|
|
|
55,090 |
|
|
|
|
|
|
366,088 |
|
|
|
218,520 |
|
|
|
|
Oil
sales |
|
67,703 |
|
|
|
71,426 |
|
|
|
|
|
|
172,575 |
|
|
|
291,122 |
|
|
|
|
Total |
$ |
545,324 |
|
|
$ |
425,520 |
|
|
28 |
% |
|
$ |
1,544,551 |
|
|
$ |
1,621,766 |
|
|
-5 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production of oil and
gas during the periods (a): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (mcf) |
|
114,480,336 |
|
|
|
97,175,602 |
|
|
18 |
% |
|
|
375,811,462 |
|
|
|
362,686,707 |
|
|
4 |
% |
NGLs
(bbl) |
|
8,245,792 |
|
|
|
4,906,615 |
|
|
68 |
% |
|
|
27,825,635 |
|
|
|
20,356,110 |
|
|
37 |
% |
Oil
(bbl) |
|
1,104,414 |
|
|
|
897,064 |
|
|
23 |
% |
|
|
3,609,171 |
|
|
|
4,084,069 |
|
|
-12 |
% |
Gas equivalent (mcfe)
(b) |
|
170,581,572 |
|
|
|
131,997,676 |
|
|
29 |
% |
|
|
564,420,298 |
|
|
|
509,327,781 |
|
|
11 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production of oil and
gas – average per day (a): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (mcf) |
|
1,244,351 |
|
|
|
1,056,257 |
|
|
18 |
% |
|
|
1,026,807 |
|
|
|
993,662 |
|
|
3 |
% |
NGLs
(bbl) |
|
89,628 |
|
|
|
53,333 |
|
|
68 |
% |
|
|
76,026 |
|
|
|
55,770 |
|
|
36 |
% |
Oil
(bbl) |
|
12,005 |
|
|
|
9,751 |
|
|
23 |
% |
|
|
9,861 |
|
|
|
11,189 |
|
|
-12 |
% |
Gas equivalent (mcfe)
(b) |
|
1,854,148 |
|
|
|
1,434,757 |
|
|
29 |
% |
|
|
1,542,132 |
|
|
|
1,395,419 |
|
|
11 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices,
including cash-settled hedges that qualify for hedge accounting
before third party transportation costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (mcf) |
$ |
2.53 |
|
|
$ |
1.89 |
|
|
34 |
% |
|
$ |
2.01 |
|
|
$ |
2.13 |
|
|
-6 |
% |
NGLs
(bbl) |
$ |
14.50 |
|
|
$ |
9.12 |
|
|
59 |
% |
|
$ |
11.44 |
|
|
$ |
8.67 |
|
|
32 |
% |
Oil
(bbl) |
$ |
44.61 |
|
|
$ |
28.70 |
|
|
55 |
% |
|
$ |
34.60 |
|
|
$ |
34.28 |
|
|
1 |
% |
Gas equivalent (mcfe)
(b) |
$ |
2.69 |
|
|
$ |
1.92 |
|
|
40 |
% |
|
$ |
2.12 |
|
|
$ |
2.14 |
|
|
-1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices,
including cash-settled hedges and derivatives before third party
transportation costs: (c) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (mcf) |
$ |
2.93 |
|
|
$ |
3.08 |
|
|
-5 |
% |
|
$ |
2.68 |
|
|
$ |
3.07 |
|
|
-13 |
% |
NGLs
(bbl) |
$ |
17.20 |
|
|
$ |
11.23 |
|
|
53 |
% |
|
$ |
13.16 |
|
|
$ |
10.73 |
|
|
23 |
% |
Oil
(bbl) |
$ |
61.30 |
|
|
$ |
79.62 |
|
|
-23 |
% |
|
$ |
47.82 |
|
|
$ |
71.28 |
|
|
-33 |
% |
Gas equivalent (mcfe)
(b) |
$ |
3.20 |
|
|
$ |
3.22 |
|
|
-1 |
% |
|
$ |
2.74 |
|
|
$ |
3.18 |
|
|
-14 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices,
including cash-settled hedges and derivatives: (d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (mcf) |
$ |
1.93 |
|
|
$ |
2.09 |
|
|
-8 |
% |
|
$ |
1.60 |
|
|
$ |
2.12 |
|
|
-24 |
% |
NGLs
(bbl) |
$ |
11.20 |
|
|
$ |
7.84 |
|
|
43 |
% |
|
$ |
7.33 |
|
|
$ |
8.12 |
|
|
-10 |
% |
Oil
(bbl) |
$ |
61.30 |
|
|
$ |
79.62 |
|
|
-23 |
% |
|
$ |
47.82 |
|
|
$ |
71.28 |
|
|
-33 |
% |
Gas equivalent (mcfe)
(b) |
$ |
2.23 |
|
|
$ |
2.37 |
|
|
-6 |
% |
|
$ |
1.74 |
|
|
$ |
2.41 |
|
|
-28 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation,
gathering, processing and compression expense per mcfe |
$ |
0.96 |
|
|
$ |
0.85 |
|
|
13 |
% |
|
$ |
1.00 |
|
|
$ |
0.78 |
|
|
29 |
% |
(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, processing
and compression costs.(d) Net of transportation, gathering,
processing 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 Ended December 31, |
|
|
Twelve Months Ended December 31, |
|
|
|
2016 |
|
|
|
2015 |
|
|
% |
|
|
|
2016 |
|
|
|
2015 |
|
|
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from operations
before income taxes, as reported |
$ |
(256,290 |
) |
|
$ |
(486,114 |
) |
|
47 |
% |
|
$ |
(802,138 |
) |
|
$ |
(1,052,362 |
) |
|
-24 |
% |
Adjustment for certain
special items: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Gain)
loss on sale of assets |
|
(470 |
) |
|
|
408,909 |
|
|
|
|
|
|
7,074 |
|
|
|
406,856 |
|
|
|
|
(Gain)
loss on ARO settlements |
|
(54 |
) |
|
|
(80 |
) |
|
|
|
|
|
(40 |
) |
|
|
(103 |
) |
|
|
|
Change in
fair value related to derivatives prior to settlement |
|
336,736 |
|
|
|
45,165 |
|
|
|
|
|
|
608,727 |
|
|
|
115,758 |
|
|
|
|
Abandonment and impairment of unproved properties |
|
6,307 |
|
|
|
11,432 |
|
|
|
|
|
|
30,076 |
|
|
|
47,619 |
|
|
|
|
Loss on
early extinguishment of debt |
|
— |
|
|
|
— |
|
|
|
|
|
|
— |
|
|
|
22,495 |
|
|
|
|
Impairment of proved property |
|
— |
|
|
|
87,941 |
|
|
|
|
|
|
43,040 |
|
|
|
590,174 |
|
|
|
|
Lawsuit
settlements |
|
1,131 |
|
|
|
1,226 |
|
|
|
|
|
|
2,575 |
|
|
|
3,238 |
|
|
|
|
Fees paid
to exchange senior subordinated notes |
|
— |
|
|
|
— |
|
|
|
|
|
|
6,600 |
|
|
|
— |
|
|
|
|
DEP
penalty |
|
— |
|
|
|
— |
|
|
|
|
|
|
— |
|
|
|
2,500 |
|
|
|
|
Memorial
merger expenses |
|
813 |
|
|
|
— |
|
|
|
|
|
|
37,225 |
|
|
|
— |
|
|
|
|
Termination costs |
|
(822 |
) |
|
|
10,283 |
|
|
|
|
|
|
(519 |
) |
|
|
14,853 |
|
|
|
|
Termination costs – non-cash stock-based compensation |
|
— |
|
|
|
(1,503 |
) |
|
|
|
|
|
— |
|
|
|
217 |
|
|
|
|
Brokered
natural gas and marketing – non-cash stock-based compensation |
|
376 |
|
|
|
389 |
|
|
|
|
|
|
1,725 |
|
|
|
2,132 |
|
|
|
|
Direct
operating – non-cash stock-based compensation |
|
521 |
|
|
|
631 |
|
|
|
|
|
|
2,302 |
|
|
|
2,780 |
|
|
|
|
Exploration expenses – non-cash stock-based compensation |
|
629 |
|
|
|
814 |
|
|
|
|
|
|
2,298 |
|
|
|
2,985 |
|
|
|
|
General
& administrative – non-cash stock-based compensation |
|
11,611 |
|
|
|
11,142 |
|
|
|
|
|
|
49,293 |
|
|
|
49,687 |
|
|
|
|
Deferred
compensation plan – non-cash adjustment |
|
(11,013 |
) |
|
|
(21,016 |
) |
|
|
|
|
|
19,153 |
|
|
|
(77,627 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income
taxes, as adjusted |
|
89,475 |
|
|
|
69,219 |
|
|
29 |
% |
|
|
7,391 |
|
|
|
131,202 |
|
|
-94 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense, as
adjusted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
98 |
|
|
|
29 |
|
|
|
|
|
|
98 |
|
|
|
29 |
|
|
|
|
Deferred
(a) |
|
33,759 |
|
|
|
27,431 |
|
|
|
|
|
|
2,426 |
|
|
|
50,777 |
|
|
|
|
Net income excluding
certain items, a non-GAAP measure |
$ |
55,618 |
|
|
$ |
41,759 |
|
|
33 |
% |
|
$ |
4,867 |
|
|
$ |
80,396 |
|
|
-94 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-GAAP income (loss)
per common share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
$ |
0.23 |
|
|
$ |
0.25 |
|
|
-8 |
% |
|
$ |
0.03 |
|
|
$ |
0.48 |
|
|
-94 |
% |
Diluted |
$ |
0.23 |
|
|
$ |
0.25 |
|
|
-8 |
% |
|
$ |
0.03 |
|
|
$ |
0.48 |
|
|
-94 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-GAAP diluted shares
outstanding, if dilutive |
|
244,761 |
|
|
|
166,881 |
|
|
|
|
|
|
189,911 |
|
|
|
166,432 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Deferred taxes for 2016 are estimated to be
approximately 38%.
|
|
RANGE RESOURCES CORPORATION |
|
|
|
HEDGING POSITION AS OF FEBRUARY 17,
2017 (Unaudited) – |
|
|
|
|
|
|
|
|
Daily Volume |
|
|
|
Hedge Price |
|
|
Gas |
|
|
|
|
|
|
|
|
|
|
2017 Swaps |
|
|
|
830,171
Mmbtu |
|
|
|
$ |
3.17 |
|
|
2017 Puts (1) |
|
|
|
175,890
Mmbtu |
|
|
|
$ |
3.17 |
|
|
2017 Collars |
|
|
|
117,123
Mmbtu |
|
|
|
$ |
3.48 x
$4.15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
1Q 2018 Swaps |
|
|
|
830,000
Mmbtu |
|
|
|
$ |
3.42 |
|
|
2Q-4Q 2018 Swaps |
|
|
|
225,000
Mmbtu |
|
|
|
$ |
2.97 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
|
|
|
|
|
|
|
|
2017 Swaps |
|
|
|
8,795
bbls |
|
|
|
$ |
55.81 |
|
|
|
|
|
|
|
|
|
|
|
|
|
2018 Swaps |
|
|
|
3,000
bbls |
|
|
|
$ |
54.36 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
C2
Ethane |
|
|
|
|
|
|
|
|
|
|
|
2017 Swaps |
|
|
|
3,000
bbls |
|
|
|
$ |
0.27/gallon |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
C3
Propane (2) |
|
|
|
|
|
|
|
|
|
|
|
2017 Swaps |
|
|
|
13,974
bbls |
|
|
|
$ |
0.56/gallon |
|
|
2018 Swaps |
|
|
|
7,199
bbls |
|
|
|
$ |
0.61/gallon |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
C4 Normal
Butane |
|
|
|
|
|
|
|
|
|
|
|
2017 Swaps |
|
|
|
7,731
bbls |
|
|
|
$ |
0.74/gallon |
|
|
2018 Swaps |
|
|
|
4,250
bbls |
|
|
|
$ |
0.81/gallon |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
C5 Natural
Gasoline |
|
|
|
|
|
|
|
|
|
|
|
2017 Swaps |
|
|
|
5,250
bbls |
|
|
|
$ |
01.06/gallon |
|
|
2017 Swaps |
|
|
|
1,500
bbls |
|
|
|
$ |
01.19/gallon |
|
(1) Net of deferred premiums
(2) Incorporates international propane spreads
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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