RANGE RESOURCES CORPORATION (NYSE:RRC) today
announced its third quarter financial results.
Highlights –
- Merger with Memorial Resource Development Corp. (“Memorial”)
closed on September 16th
- Gulf Markets Expansion pipeline on line in early October
improves natural gas netbacks by moving 150,000 Mmbtu per day of
Range natural gas from Appalachia to Gulf Coast markets
- North Louisiana production growth and additional takeaway
projects result in better natural gas differentials going
forward
- New condensate sales agreements commenced July 1, improving
condensate prices by approximately $7.00 per barrel compared to the
previous quarter
- NGL pricing improved to 25% of WTI compared to 13% of WTI in
the prior-year quarter
- Third quarter production averaged a record 1,508 net Mmcfe per
day
- Southern Marcellus production averaged a record 1,228 net Mmcfe
per day, up 23% from the prior-year quarter
- Unit costs improved by 3%, or $0.09 per mcfe, compared to
prior-year quarter
Commenting, Jeff Ventura, the Company’s CEO
said, “Range reached another milestone in the Company’s history
with the closing of the Memorial merger on September 16th.
Combining the North Louisiana stacked pay assets with our extensive
Marcellus/Utica inventory makes Range a better and stronger
company, with geographic diversity that allows us flexibility in
capital allocation and marketing. The integration of North
Louisiana’s operations is going well and we expect the combined
experience and skills from both teams will enhance the value of
these high-quality assets.
Third quarter results were encouraging, as
production increased, unit costs improved and unhedged cash margins
rebounded. We are excited as we look forward to fourth
quarter 2016 and the full year 2017, as we anticipate improving
margins on all of our products and continued improvement in capital
efficiency across the Company. With our extensive opportunity
set in two high-quality natural gas plays, we believe Range is in a
great position to drive shareholder value for many years to
come.”
Financial Discussion
Except for generally accepted accounting
principles (“GAAP”) reported amounts, specific expense categories
exclude non-cash impairments, unrealized mark-to-market gain or
loss 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.
Third Quarter 2016
GAAP revenues for third quarter 2016 totaled
$413 million (a 14% decrease compared to third quarter 2015).
GAAP net cash provided from operating activities including changes
in working capital was $32 million compared to $145 million in
third quarter 2015 and GAAP earnings were a loss of $42 million
($0.23 loss per diluted share) versus a loss of $301 million ($1.81
per diluted share) in the prior-year quarter. Third quarter
2016 included a $65 million derivative gain due to decreased
commodity prices, compared to a $202 million gain in 2015.
Third quarter 2016 also included a deferred compensation plan gain
of $12 million, due to the decrease in Range’s stock price during
the quarter, compared to a $44 million gain in the prior-year
quarter.
Non-GAAP revenues for third quarter 2016 totaled
$402 million (a 3% decrease compared to third quarter 2015), cash
flow from operations before changes in working capital, a non-GAAP
measure, was $123 million compared to $169 million in third quarter
2015. Adjusted net income comparable to analysts’ estimates,
a non-GAAP measure, was a loss of $10.4 million ($0.06 loss per
diluted share) for the third quarter 2016 compared to earnings of
$5.5 million ($0.03 per diluted share) in the prior-year
quarter. The Company’s total unit costs improved by $0.09 per
mcfe, or 3%, compared to the prior-year quarter, as shown
below:
Expenses |
|
3Q 2016
(per mcfe) |
|
|
|
3Q 2015
(per mcfe) |
|
|
|
Increase (Decrease) |
|
|
|
|
|
|
|
|
|
|
|
Direct operating |
$ |
0.16 |
|
|
$ |
0.26 |
|
|
$ |
|
(38 |
%) |
Transportation, gathering, processing &
compression |
|
1.00 |
|
|
|
0.75 |
|
|
|
|
33 |
% |
Production and ad
valorem taxes |
|
0.05 |
|
|
|
0.06 |
|
|
|
|
(17 |
%) |
General and
administrative |
|
0.21 |
|
|
|
0.25 |
|
|
|
|
(16 |
%) |
Interest expense |
|
0.33 |
|
|
|
0.32 |
|
|
|
|
3 |
% |
Total cash unit costs (a) |
|
1.75 |
|
|
|
1.64 |
|
|
|
|
7 |
% |
Depletion, depreciation
amortization |
|
0.95 |
|
|
|
1.16 |
|
|
|
|
(18 |
%) |
Total unit costs (a) |
$ |
2.70 |
|
|
$ |
2.79 |
|
|
$ |
|
(3 |
%) |
(a) Totals may not add due to rounding.
Third quarter 2016 natural gas, NGLs and oil
differentials all improved compared to the prior year as a result
of transportation capacity, marketing contracts and 15 days of
production from the newly acquired North Louisiana assets.
Additional detail on commodity price realizations can be found in
the Supplemental Tables provided on the Company’s website
at www.rangeresources.com.
- Production and realized prices, including hedging settlements,
by each commodity for third quarter 2016 were: natural gas –
1,016 Mmcf per day ($2.50 per mcf), NGLs – 73,252 barrels per day
($12.43 per barrel) and crude oil and condensate – 8,814
barrels per day ($49.97 per barrel). Total third
quarter production was 1,508 Mmcfe per day ($2.58 per
mcfe).
- The third quarter average natural gas price, before NYMEX
hedging settlements, was $2.14 per mcf as compared to $1.98 per mcf
in the prior-year quarter. The average Company natural gas
price differential including the impact of basis hedges for the
third quarter improved to ($0.68) per mcf compared to ($0.78) per
mcf in the prior-year quarter, as a result of increased capacity to
better markets and 15 days of production from the newly acquired
North Louisiana assets. NYMEX natural gas financial hedges
increased realizations $0.35 per mcf in the third quarter
2016.
- Total NGL pricing per barrel including ethane and processing
expenses before hedging settlements improved to 25% of WTI ($11.17
per barrel) compared to 13% of WTI ($6.23 per barrel) in the
prior-year quarter as a result of increased NGL capacity to better
markets, mainly due to Mariner East. Hedging increased NGL
prices by $1.26 per barrel in the third quarter 2016.
- Crude oil and condensate price realizations, before realized
hedges, for the third quarter averaged $39.15 per barrel, or $5.81
below WTI, compared to $13.35 below WTI in the prior-year
quarter. The improved differential primarily resulted from
new condensate sales agreements in southwest Pennsylvania that
began on July 1, 2016. Hedging added $10.82 per barrel in the
third quarter 2016.
Capital Expenditures
Third quarter 2016 drilling expenditures of $90
million funded the drilling of 39 (38 net) wells. A 100%
success rate was achieved. In addition, during the quarter,
$7.4 million was incurred on acreage purchases, $6.3 million on
exploration expense, and $0.3 million on gas gathering
systems. Range is on target with its previously announced
$495 million capital budget for 2016, not including the North
Louisiana Division. Capital expenditures in fourth quarter
2016 for the North Louisiana Division is expected to be $74
million. The Company expects to average nine rigs running for
the fourth quarter of 2016, with five in the Southern Marcellus
Division and four in the North Louisiana Division.
A new slide has been added to Range’s investor
presentation on page seven, available on Range’s website at
www.rangeresources.com. The slide depicts a preliminary view
of 2017 and 2018 year-over-year production growth, based on current
strip pricing in 2017 and assuming $3.25 and $60.00 prices for
natural gas and oil respectively in 2018. Year-over-year
production growth in 2017 is expected to be 33% to 35% with the
inclusion of a full year of activity for the North Louisiana assets
in 2017, or 11% to 13% of organic growth. Anticipated
year-over-year production growth in 2018 is projected to be
approximately 20%.
The Company expects to announce the details for
the 2017 capital plan in February, following approval by the
Company’s Board of Directors.
Financial Position and
Liquidity
Effective with the closing of the Memorial
merger on September 16, 2016, Memorial’s bank credit facility was
repaid and terminated, with the borrowings funded under Range’s
existing bank credit facility. The additional collateral of
the North Louisiana assets support Range’s unchanged $4 billion
credit facility with a $3 billion borrowing base and $2 billion
committed amount. As of September 30, 2016, the outstanding
balance under Range’s bank facility was $937 million, before debt
issuance costs, and $254 million in undrawn letter of credit,
leaving $809 million of committed liquidity. At September 30,
2016, Range’s bank group was composed of 29 financial institutions,
with no bank holding more than 5.8% of the total facility.
The facility matures in October of 2019 and provides for annual
redeterminations, with the next redetermination expected by May
2017.
Concurrent with the closing of the Memorial
merger, Range completed a series of exchange and tender offers that
streamlined and standardized covenants across the debt capital
structure. This standardization enhances the Company’s
financial flexibility and facilitates investor analysis of the debt
securities. Of the $600 million in Memorial Senior Notes, Range
received 99.8% participation in its offers to either exchange for
newly issued Range Senior Notes or to redeem them in cash.
Simultaneously Range received 97.2% acceptance of its offer to
exchange Range’s Senior Subordinated Notes for newly issued Senior
Notes of identical maturity and coupon.
Operational Discussion
Range has updated its investor presentation with
third quarter financial and operational results. Please see
www.rangeresources.com under the Investors tab, “Company
Presentations” area, for the presentation entitled, “Company
Presentation – October 25, 2016.”
The table below summarizes year-to-date activity
and the number of wells expected to be turned to sales for the
remainder of 2016.
Area |
|
Wells to sales YTD @ 9/30/16 |
|
Remaining Fourth quarter |
|
Planned Total Wells to sales in
2016 |
Super-Rich |
|
13 |
|
1 |
|
14 |
Wet |
|
26 |
|
- |
|
26 |
Dry - SW |
|
42 |
|
- |
|
42 |
Dry - NE |
|
12 |
|
5 |
|
17 |
Total Marcellus/Utica |
|
93 |
|
6 |
|
99 |
N. Louisiana |
|
39 |
|
3 |
|
42 |
Total Company |
|
132 |
|
9 |
|
141 |
Several Marcellus wells that were previously
expected to be turned to sales late in fourth quarter 2016 are now
expected in the first two weeks of 2017. This small
adjustment has been captured in the Company’s fourth quarter
production guidance, which remains on track with previous guidance.
In addition, the North Louisiana Division has approximately
25 drilled but uncompleted wells which are expected to be turned to
sales in first quarter 2017.
Marcellus Shale
Total Marcellus production for the third quarter
averaged 1,396 net Mmcfe per day, a 9% increase over the prior-year
quarter. The Southern Marcellus Shale Division averaged 1,228
net Mmcfe per day during the quarter, a 23% increase over the
prior-year quarter. The Northern Marcellus Shale Division
averaged 169 net Mmcf per day during the quarter, a 39% decrease
compared to the prior-year quarter, resulting from the sale of our
Bradford County non-operated assets effective January 1, 2016,
combined with a reduction in activity.
The Southern Marcellus Shale Division continues
to drill and complete outstanding wells, with peer-leading EURs,
while continuing to drive costs lower. The examples below
represent recent wells brought on line that continue to perform
well.
- In the southwest dry area, a four well pad brought on line in
August is expected to have an EUR of approximately 16.0 Bcf per
well, or over 3.0 Bcf per 1,000 lateral feet, at a cost of
approximately $5.1 million per well.
- In the wet area, a four well pad brought on line at the end of
July is expected to have an EUR of approximately 27.0 Bcfe per
well, or 4.0 Bcfe per 1,000 lateral feet, at a cost of
approximately $5.7 million per well.
Operational efficiency gains continued in the
third quarter. Year to date through September, the division
completed 2,854 stages, compared to 2,643 stages in the previous
year, an 8% increase, despite a reduction in overall activity and
capital spending.
Range also continues to drill faster and more
efficiently. Year to date through September, Range drilled
22% more lateral feet per day per rig, with a 5% reduction in
drilling cost per lateral foot, when compared to the prior-year
quarter. Logistical improvements in water handling have
resulted in annual savings of over $20 million, and costs of road
construction have been reduced by 39% per mile over the past year.
These and other efficiencies have driven Range’s normalized (per
1,000 feet of lateral) well costs, including surface facility
costs, to among the lowest of other Marcellus peers.
North Louisiana
Although it has only been approximately 40 days
since the closing of the Memorial merger, integration of the teams
and assets has progressed quickly. The North Louisiana assets
will be operated as a new Range division, under the direction of
Senior Vice President - John Applegath, who for the past five years
led Range’s Southern Marcellus Division. John has an
extensive energy industry background in areas all over the world,
including prior experience with drilling and completion operations
in the Cotton Valley formation.
For the third quarter, the division brought on
line 16 wells, all located in the Terryville field. Even with
some outstanding well results over the past year, the team is
focused on continued improvement in recoveries and capital
efficiency. Some recent examples include:
- Two recent Terryville wells recorded spud to rig release in 30
days, compared to a year-to-date average of 40 days.
- A recent Terryville well had a 30 day average rate to sales of
27 Mmcfe per day, or 4.7 Mmcfe per day per 1,000 lateral feet, one
of the top wells drilled in the field to date on a normalized
basis.
- Range’s experience in studying, isolating and improving
formation targeting has the potential to increase recoveries and
improve consistency of results.
- Targeting of porosity intervals has been improved to a range of
20 to 40 feet compared to the previous interval of 100 to 125
feet.
- Recent wells have stayed within the new target range for the
entire lateral. These wells are expected to be completed and
brought on line in first quarter 2017.
- Range’s purchasing power combined with supply chain logistics
has resulted in a 7% savings in casing costs.
There are currently three wells in progress in
the extension acreage area, south of the Terryville field.
Based on log analysis, gas-in-place analysis and reservoir pressure
data, combined with the stacked-pay potential in the area, Range is
encouraged. Two of the wells are currently being completed
and the third well is still in the drilling phase. Range
expects to have well results by the end of the year.
Marketing and Transportation
Range’s marketing team has a track record of
innovative and diversified marketing solutions across all
products. The second half of 2016 marks the confluence of
several events that improve Range’s differentials and marketing
options going forward. The most notable event is the addition
of the North Louisiana Division. The newly acquired North
Louisiana assets and production provide additional diversification
and opportunities as the Company expects to explore new options for
selling products in the Gulf Coast markets, where additional demand
is expected from LNG exports, Mexican exports, power generation and
the petrochemical industry. Having the ability to sell
production near seasonally strong Northeast and Midwest population
centers while also having the expanded marketing ability near
growing demand in the Gulf Coast area is expected to be a marketing
advantage going forward.
For natural gas, Spectra’s Gulf Markets
Expansion pipeline came on line in early October moving 150,000
Mmbtu per day of Range natural gas from Appalachia to markets close
to the Gulf Coast. At the same time the increased North
Louisiana natural gas production bolsters Range’s natural gas
realizations going forward given its proximity to the Gulf
Coast. As a result, Range’s fourth quarter natural gas
differential is anticipated to improve to approximately $0.46 per
mcf below NYMEX and the Company expects further improvement in 2017
to approximately $0.30 to $0.35 per mcf below NYMEX, based on
current strip pricing. Towards the end of 2017, Range has
capacity on several Appalachian takeaway projects in southwest
Pennsylvania that are expected to be completed on time that should
result in additional improvements in 2018.
For NGLs, Range recently supplied a shipment of
ethane to INEOS’ facilities in Grangemouth, Scotland. This
was the first shipment to the United Kingdom of ethane produced
from shale reservoirs. Range is proud to have played a
significant role in this event which demonstrates one of Range’s
innovative marketing solutions for its growing NGL
production. In addition, Range continues to sell propane from
the Marcus Hook export terminal, placing over 1.8 million barrels
of Range propane into international markets during the third
quarter of 2016. As a result of these exports, the full
utilization of Range’s NGL marketing options and the addition of
North Louisiana production, Range expects NGL realizations to
improve to over 26% of WTI for the fourth quarter of 2016 and
full-year 2017.
Regarding condensate, Range entered into
long-term agreements in early July that will serve two Midwest
refineries in purchasing condensate from southwest
Pennsylvania. The contracts largely drove the improvement in
Marcellus condensate prices by approximately $7 per barrel during
the quarter. At the same time, Range’s condensate production
in North Louisiana receives favorable pricing given its proximity
to the Gulf Coast. Combined, the Company expects the
condensate differential to WTI to improve substantially to
approximately $6.00 - $7.00 per barrel below NYMEX in the fourth
quarter of 2016 and full-year 2017.
Guidance
Production per day Guidance
Production for the fourth quarter of 2016 is
expected to be approximately 1,850 Mmcfe per day with 31% to 33%
liquids.
Fourth Quarter 2016 Expense Guidance
Direct operating
expense: |
|
$0.18
– $0.19 per mcfe |
Transportation, gathering
and compression expense: |
|
$1.03
– $1.04 per mcfe |
Production tax
expense: |
|
$0.05
– $0.06 per mcfe |
Exploration expense: |
|
$ 13.0
– $15.0 million* |
Unproved property
impairment expense: |
|
$ 7.0
– $9.0 million |
G&A expense: |
|
$0.22
– $0.24 per mcfe |
Interest expense: |
|
$0.27
– $0.29 per mcfe |
DD&A expense: |
|
$0.95
– $0.96 per mcfe |
Net Brokered Gas Marketing
Expense: |
|
~$2.0 million |
|
|
|
*Includes North Louisiana seismic expense of approximately $5.5
million for fourth quarter 2016
Differential Calculation
Based on current market pricing indications, Range would expect
to average the following pre-hedge differentials for its fourth
quarter 2016 and full year 2017 production.
|
|
4th Quarter 2016 |
Full-Year 2017 |
Natural Gas: |
|
NYMEX
less $0.46 |
NYMEX
less $0.30 - $0.35 |
Natural Gas Liquids
(including ethane): |
|
26%
- 28% of WTI |
26%
- 28% of WTI |
Oil/Condensate: |
|
WTI
minus$6.00 - $7.00 |
WTI
minus$6.00 - $7.00 |
|
|
|
|
Hedging Status
Range hedges portions of its expected future
production volumes to increase the predictability of cash
flow. Range currently has over 80% of its remaining 2016
natural gas production hedged at a weighted average floor price of
$3.32 per mcf. Range has approximately 50% of its expected
2017 gas production hedged at an average floor price of $3.21 with
approximately 15% hedged using puts and collars which allow
additional upside. Similarly, Range has hedged over 80% of
its remaining 2016 projected crude oil production at a floor price
of $70.43 and approximately 85% of its composite fourth quarter
2016 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 hedged Marcellus and other basis
differentials covering 59,385,000 Mmbtu per day for October 2016
through December 2017. The fair value of the basis hedges
based upon future strip prices as of September 30, 2016 was a gain
of $13.8 million.
Range has also hedged the premium spread between
the Mont Belvieu propane index and the respective
European and Asian propane market indexes on approximately 33% of
anticipated LPG sales through December 2017. The fair value
of these hedges based upon future strip prices as of September 30,
2016 was a gain of $4.1 million.
Conference Call and Webcast
Information
A conference call to review the financial
results is scheduled on Wednesday, October 26 at 9:00 a.m. ET. To
participate in the call, please dial 866-900-7525 and provide
conference code 92858145 about 10 minutes prior to the scheduled
start time.
A simultaneous webcast of the call may be
accessed over the internet at www.rangeresources.com. The
webcast will be archived for replay on the Company’s website until
November 26.
Non-GAAP Financial Measures
Adjusted net income or loss comparable to
analysts’ estimates as set forth in this release represents income
or loss 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 to adjusted net income
(loss) 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 from operating
activities 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 operating activities, investing, or financing activities as an
indicator of cash flows, or as a measure of liquidity. A
table is included which reconciles net cash from operating
activities 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 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 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 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 Quarterly
Report on Form 10-Q. 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 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, including, but not limited to, the
volatility of oil and gas prices, the results of our hedging
transactions, the costs and results of actual drilling and
operations, the timing of production, mechanical and other inherent
risks associated with oil and gas production, weather, the
availability of drilling equipment, changes in interest rates,
litigation, uncertainties about reserve estimates, environmental
risks and regulatory changes, the ultimate timing, outcome and
results of integrating the operations of Range and Memorial
Resource Development Corp. (“MRD”); the effects of the business
combination of Range and MRD, including the combined company’s
future financial condition, results of operations, strategy and
plans; potential adverse reactions or changes to business
relationships resulting from the completion of the business
combination; expected synergies and other benefits from the
business combination and the ability of Range to realize such
synergies and other benefits. Range undertakes no obligation
to publicly update or revise any 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.
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.
RANGE RESOURCES CORPORATION |
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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-Q |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited, in
thousands, except per share data) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
Nine Months Ended September 30, |
|
|
2016 |
|
|
|
2015 |
|
|
|
% |
|
|
|
2016 |
|
|
|
2015 |
|
|
|
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues and other
income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, NGLs and oil sales
(a) |
$ |
304,477 |
|
|
$ |
252,065 |
|
|
|
|
|
|
$ |
738,570 |
|
|
$ |
835,601 |
|
|
|
|
|
Derivative fair value
income/(loss) |
|
64,556 |
|
|
|
202,004 |
|
|
|
|
|
|
|
(11,334 |
) |
|
|
290,052 |
|
|
|
|
|
Brokered natural gas, marketing and
other (b) |
|
44,114 |
|
|
|
25,141 |
|
|
|
|
|
|
|
118,445 |
|
|
|
60,822 |
|
|
|
|
|
ARO settlement loss (b) |
|
(6 |
) |
|
|
(5 |
) |
|
|
|
|
|
|
(14 |
) |
|
|
23 |
|
|
|
|
|
Other (b) |
|
66 |
|
|
|
728 |
|
|
|
|
|
|
|
750 |
|
|
|
843 |
|
|
|
|
|
Total revenues and other
income |
|
413,207 |
|
|
|
479,933 |
|
|
|
-14 |
% |
|
|
846,417 |
|
|
|
1,187,341 |
|
|
|
-29 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and
expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating |
|
21,890 |
|
|
|
34,449 |
|
|
|
|
|
|
|
65,331 |
|
|
|
104,826 |
|
|
|
|
|
Direct operating – non-cash
stock-based compensation (c) |
|
497 |
|
|
|
609 |
|
|
|
|
|
|
|
1,781 |
|
|
|
2,149 |
|
|
|
|
|
Transportation, gathering,
processing and compression |
|
138,764 |
|
|
|
99,634 |
|
|
|
|
|
|
|
400,871 |
|
|
|
284,258 |
|
|
|
|
|
Production and ad valorem
taxes |
|
6,717 |
|
|
|
7,336 |
|
|
|
|
|
|
|
18,653 |
|
|
|
26,506 |
|
|
|
|
|
Brokered natural gas and
marketing |
|
44,167 |
|
|
|
31,713 |
|
|
|
|
|
|
|
120,756 |
|
|
|
79,181 |
|
|
|
|
|
Brokered natural gas and marketing
– non-cash stock-based compensation (c) |
|
455 |
|
|
|
618 |
|
|
|
|
|
|
|
1,349 |
|
|
|
1,743 |
|
|
|
|
|
Exploration |
|
6,335 |
|
|
|
3,547 |
|
|
|
|
|
|
|
16,972 |
|
|
|
14,975 |
|
|
|
|
|
Exploration – non-cash stock-based
compensation (c) |
|
608 |
|
|
|
688 |
|
|
|
|
|
|
|
1,669 |
|
|
|
2,171 |
|
|
|
|
|
Abandonment and impairment of
unproved properties |
|
6,082 |
|
|
|
12,366 |
|
|
|
|
|
|
|
23,769 |
|
|
|
36,187 |
|
|
|
|
|
General and
administrative |
|
29,428 |
|
|
|
33,038 |
|
|
|
|
|
|
|
87,819 |
|
|
|
106,814 |
|
|
|
|
|
General and administrative –
non-cash stock-based compensation (c) |
|
11,126 |
|
|
|
11,512 |
|
|
|
|
|
|
|
37,682 |
|
|
|
38,545 |
|
|
|
|
|
General and administrative –
lawsuit settlements |
|
120 |
|
|
|
1,278 |
|
|
|
|
|
|
|
1,444 |
|
|
|
2,012 |
|
|
|
|
|
General and administrative – bad
debt expense |
|
350 |
|
|
|
350 |
|
|
|
|
|
|
|
800 |
|
|
|
600 |
|
|
|
|
|
General and administrative – DEP
penalty |
|
– |
|
|
|
– |
|
|
|
|
|
|
|
– |
|
|
|
2,500 |
|
|
|
|
|
Memorial merger expenses |
|
33,791 |
|
|
|
– |
|
|
|
|
|
|
|
36,412 |
|
|
|
– |
|
|
|
|
|
Termination costs |
|
136 |
|
|
|
(76 |
) |
|
|
|
|
|
|
303 |
|
|
|
4,570 |
|
|
|
|
|
Termination costs – non-cash
stock-based compensation (c) |
|
– |
|
|
|
(1 |
) |
|
|
|
|
|
|
– |
|
|
|
1,720 |
|
|
|
|
|
Deferred compensation plan (d) |
|
(11,636 |
) |
|
|
(43,705 |
) |
|
|
|
|
|
|
30,166 |
|
|
|
(56,611 |
) |
|
|
|
|
Interest expense |
|
45,967 |
|
|
|
42,904 |
|
|
|
|
|
|
|
121,464 |
|
|
|
125,590 |
|
|
|
|
|
Loss on early extinguishment of
debt |
|
– |
|
|
|
22,495 |
|
|
|
|
|
|
|
– |
|
|
|
22,495 |
|
|
|
|
|
Depletion, depreciation and
amortization |
|
131,489 |
|
|
|
153,993 |
|
|
|
|
|
|
|
374,440 |
|
|
|
453,178 |
|
|
|
|
|
Impairment of proved properties and
other assets |
|
– |
|
|
|
502,233 |
|
|
|
|
|
|
|
43,040 |
|
|
|
502,233 |
|
|
|
|
|
Loss (gain) on sale of assets |
|
2,597 |
|
|
|
681 |
|
|
|
|
|
|
|
7,544 |
|
|
|
(2,053 |
) |
|
|
|
|
Total costs and expenses |
|
468,883 |
|
|
|
915,662 |
|
|
|
49 |
% |
|
|
1,392,265 |
|
|
|
1,753,589 |
|
|
|
21 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income
taxes |
|
(55,676 |
) |
|
|
(435,729 |
) |
|
|
87 |
% |
|
|
(545,848 |
) |
|
|
(566,248 |
) |
|
|
4 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax benefit: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
– |
|
|
|
– |
|
|
|
|
|
|
|
– |
|
|
|
– |
|
|
|
|
|
Deferred |
|
(13,705 |
) |
|
|
(134,781 |
) |
|
|
|
|
|
|
(187,231 |
) |
|
|
(174,390 |
) |
|
|
|
|
|
|
(13,705 |
) |
|
|
(134,781 |
) |
|
|
|
|
|
|
(187,231 |
) |
|
|
(174,390 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
$ |
(41,971 |
) |
|
$ |
(300,948 |
) |
|
|
86 |
% |
|
$ |
(358,617 |
) |
|
$ |
(391,858 |
) |
|
|
8 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Loss Per
Common Share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
$ |
(0.23 |
) |
|
$ |
(1.81 |
) |
|
|
|
|
|
$ |
(2.09 |
) |
|
$ |
(2.36 |
) |
|
|
|
|
Diluted |
$ |
(0.23 |
) |
|
$ |
(1.81 |
) |
|
|
|
|
|
$ |
(2.09 |
) |
|
$ |
(2.36 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common
shares outstanding, as reported: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
180,683 |
|
|
|
166,517 |
|
|
|
9 |
% |
|
|
171,571 |
|
|
|
166,327 |
|
|
|
3 |
% |
Diluted |
|
180,683 |
|
|
|
166,517 |
|
|
|
9 |
% |
|
|
171,571 |
|
|
|
166,327 |
|
|
|
3 |
% |
(a) See separate natural gas, NGLs and oil sales information
table.(b) Included in Brokered natural gas, marketing and other
revenues in the 10-Q.(c) Costs associated with stock compensation
and restricted stock amortization, which have been reflected in the
categories associated with the direct personnel costs, which are
combined with the cash costs in the 10-Q.(d) Reflects the change in
market value of the vested Company stock held in the deferred
compensation plan.
RANGE RESOURCES CORPORATION |
|
BALANCE
SHEETS |
|
|
|
|
|
|
|
(In thousands) |
|
September
30, |
|
|
|
December
31, |
|
|
|
2016 |
|
|
|
2015 |
|
|
|
(Unaudited) |
|
|
|
(Audited) |
|
Assets |
|
|
|
|
|
|
|
Current assets |
$ |
220,870 |
|
|
$ |
157,530 |
|
Derivative assets |
|
179,820 |
|
|
|
288,762 |
|
Goodwill |
|
1,630,981 |
|
|
|
– |
|
Natural gas and oil properties,
successful efforts method |
|
9,206,100 |
|
|
|
6,361,305 |
|
Transportation and field
assets |
|
18,308 |
|
|
|
19,455 |
|
Other |
|
71,180 |
|
|
|
72,979 |
|
|
$ |
11,327,259 |
|
|
$ |
6,900,031 |
|
|
|
|
|
|
|
|
|
Liabilities and
Stockholders’ Equity |
|
|
|
|
|
|
|
Current liabilities |
$ |
439,786 |
|
|
$ |
335,513 |
|
Asset retirement obligations |
|
15,071 |
|
|
|
15,071 |
|
Derivative liabilities |
|
7,277 |
|
|
|
1,136 |
|
|
|
|
|
|
|
|
|
Bank debt |
|
930,669 |
|
|
|
86,427 |
|
Senior notes |
|
2,847,564 |
|
|
|
738,101 |
|
Senior subordinated notes |
|
48,476 |
|
|
|
1,826,775 |
|
Total debt |
|
3,826,709 |
|
|
|
2,651,303 |
|
|
|
|
|
|
|
|
|
Deferred tax liability |
|
1,176,353 |
|
|
|
777,947 |
|
Derivative liabilities |
|
3,934 |
|
|
|
21 |
|
Deferred compensation
liability |
|
119,645 |
|
|
|
104,792 |
|
Asset retirement obligations and
other liabilities |
|
277,671 |
|
|
|
254,590 |
|
|
|
|
|
|
|
|
|
Common stock and retained
earnings |
|
5,462,514 |
|
|
|
2,761,903 |
|
Common stock held in treasury
stock |
|
(1,701 |
) |
|
|
(2,245 |
) |
Total stockholders’ equity |
|
5,460,813 |
|
|
|
2,759,658 |
|
|
$ |
11,327,259 |
|
|
$ |
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 September 30, |
|
Nine Months EndedSeptember 30, |
|
|
|
2016 |
|
|
|
2015 |
|
|
|
% |
|
|
|
2016 |
|
|
|
2015 |
|
|
|
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues and other
income, as reported |
$ |
413,207 |
|
|
$ |
479,933 |
|
|
|
-14 |
% |
|
$ |
846,417 |
|
|
$ |
1,187,341 |
|
|
|
-29 |
% |
|
Adjustment for certain
special items: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total change in fair value related
to derivatives prior to settlement (gain) loss |
|
(11,443 |
) |
|
|
(64,075 |
) |
|
|
|
|
|
|
271,991 |
|
|
|
70,593 |
|
|
|
|
|
|
ARO settlement (gain) loss |
|
6 |
|
|
|
5 |
|
|
|
|
|
|
|
14 |
|
|
|
(23 |
) |
|
|
|
|
|
Total revenues, as adjusted, non-GAAP |
$ |
401,770 |
|
|
$ |
415,863 |
|
|
|
-3 |
% |
|
$ |
1,118,422 |
|
|
$ |
1,257,911 |
|
|
|
-11 |
% |
|
RANGE RESOURCES CORPORATION |
|
CASH FLOWS FROM
OPERATING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited in
thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2016 |
|
|
|
2015 |
|
|
|
2016 |
|
|
|
2015 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
$ |
(41,971 |
) |
|
$ |
(300,948 |
) |
|
$ |
(358,617 |
) |
|
$ |
(391,858 |
) |
Adjustments to
reconcile net cash provided from continuing operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax benefit |
|
(13,705 |
) |
|
|
(134,781 |
) |
|
|
(187,231 |
) |
|
|
(174,390 |
) |
Depletion, depreciation,
amortization and impairment |
|
131,489 |
|
|
|
656,226 |
|
|
|
417,480 |
|
|
|
955,411 |
|
Exploration dry hole costs |
|
2 |
|
|
|
(19 |
) |
|
|
2 |
|
|
|
87 |
|
Abandonment and impairment of
unproved properties |
|
6,082 |
|
|
|
12,366 |
|
|
|
23,769 |
|
|
|
36,187 |
|
Derivative fair value loss
(income) |
|
(64,556 |
) |
|
|
(202,004 |
) |
|
|
11,334 |
|
|
|
(290,052 |
) |
Cash settlements on derivative
financial instruments that do not qualify for hedge accounting |
|
53,113 |
|
|
|
137,929 |
|
|
|
260,657 |
|
|
|
360,645 |
|
Allowance for bad debts |
|
350 |
|
|
|
350 |
|
|
|
800 |
|
|
|
600 |
|
Amortization of deferred issuance
costs, loss on extinguishment of debt, and other |
|
1,946 |
|
|
|
24,482 |
|
|
|
5,383 |
|
|
|
27,572 |
|
Deferred and stock-based
compensation |
|
971 |
|
|
|
(30,471 |
) |
|
|
72,689 |
|
|
|
(10,679 |
) |
(Loss) gain on sale of assets and
other |
|
2,597 |
|
|
|
681 |
|
|
|
7,544 |
|
|
|
(2,053 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in working
capital: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
(9,970 |
) |
|
|
5,753 |
|
|
|
31,985 |
|
|
|
79,448 |
|
Inventory and other |
|
(11,276 |
) |
|
|
(3,324 |
) |
|
|
(776 |
) |
|
|
(7,073 |
) |
Accounts payable |
|
(22,074 |
) |
|
|
(16,650 |
) |
|
|
(41,268 |
) |
|
|
(13,158 |
) |
Accrued liabilities and other |
|
(565 |
) |
|
|
(4,172 |
) |
|
|
(41,714 |
) |
|
|
(55,127 |
) |
Net changes in working capital |
|
(43,885 |
) |
|
|
(18,393 |
) |
|
|
(51,773 |
) |
|
|
4,090 |
|
Net cash provided from operating
activities |
$ |
32,433 |
|
|
$ |
145,418 |
|
|
$ |
202,037 |
|
|
$ |
515,560 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RECONCILIATION OF
NET CASH PROVIDED FROM OPERATING ACTIVITIES, AS REPORTED, TO CASH
FLOW FROM OPERATIONS BEFORE CHANGES IN WORKING CAPITAL, a non-GAAP
measure |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited, in
thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2016 |
|
|
|
2015 |
|
|
|
2016 |
|
|
|
2015 |
|
Net cash provided from
operating activities, as reported |
$ |
32,433 |
|
|
$ |
145,418 |
|
|
$ |
202,037 |
|
|
$ |
515,560 |
|
Net changes in working capital |
|
43,885 |
|
|
|
18,393 |
|
|
|
51,773 |
|
|
|
(4,090 |
) |
Exploration expense |
|
6,333 |
|
|
|
3,566 |
|
|
|
16,970 |
|
|
|
14,888 |
|
Lawsuit settlements |
|
120 |
|
|
|
1,278 |
|
|
|
1,444 |
|
|
|
2,012 |
|
Cash paid to exchange senior
subordinated notes |
|
6,600 |
|
|
|
– |
|
|
|
6,600 |
|
|
|
– |
|
Legal contingency/DEP penalty |
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
2,500 |
|
Memorial merger expenses |
|
33,791 |
|
|
|
– |
|
|
|
36,412 |
|
|
|
– |
|
Termination costs |
|
136 |
|
|
|
(76 |
) |
|
|
303 |
|
|
|
4,570 |
|
Non-cash compensation
adjustment |
|
(79 |
) |
|
|
46 |
|
|
|
(37 |
) |
|
|
636 |
|
Cash flow from operations before changes in
working capital – non-GAAP measure |
$ |
123,219 |
|
|
$ |
168,625 |
|
|
$ |
315,502 |
|
|
$ |
536,076 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED AVERAGE
SHARES OUTSTANDING |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited, in
thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2016 |
|
|
|
2015 |
|
|
|
2016 |
|
|
|
2015 |
|
Basic: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares
outstanding |
|
247,145 |
|
|
|
169,362 |
|
|
|
247,145 |
|
|
|
169,142 |
|
Impact of shares issued
for Memorial acquisition |
|
(63,654 |
) |
|
|
– |
|
|
|
(72,784 |
) |
|
|
– |
|
Stock held by deferred
compensation plan |
|
(2,808 |
) |
|
|
(2,845 |
) |
|
|
(2,790 |
) |
|
|
(2,815 |
) |
Basic |
|
180,683 |
|
|
|
166,517 |
|
|
|
171,571 |
|
|
|
166,327 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares
outstanding |
|
247,145 |
|
|
|
169,362 |
|
|
|
247,145 |
|
|
|
169,142 |
|
Impact of shares issued
for Memorial acquisition |
|
(63,654 |
) |
|
|
– |
|
|
|
(72,784 |
) |
|
|
– |
|
Stock held by deferred
compensation plan |
|
(2,808 |
) |
|
|
(2,845 |
) |
|
|
(2,790 |
) |
|
|
(2,815 |
) |
Diluted |
|
180,683 |
|
|
|
166,517 |
|
|
|
171,571 |
|
|
|
166,327 |
|
RANGE RESOURCES CORPORATION |
|
RECONCILIATION
OF NATURAL GAS, NGLs AND OIL SALES AND DERIVATIVE FAIR VALUE INCOME
(LOSS) TO CALCULATED CASH REALIZED NATURAL GAS, NGLs AND OIL PRICES
WITH AND WITHOUT THIRD PARTY TRANSPORTATION, GATHERING AND
COMPRESSION FEES, a non-GAAP measure |
|
|
|
|
|
(Unaudited, in
thousands, except per unit data) |
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2016 |
|
|
|
2015 |
|
|
|
% |
|
|
|
2016 |
|
|
|
2015 |
|
|
|
% |
|
Natural gas, NGL and oil
sales components: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales |
$ |
197,476 |
|
|
$ |
189,113 |
|
|
|
|
|
|
$ |
464,098 |
|
|
$ |
589,517 |
|
|
|
|
|
NGL sales |
|
75,259 |
|
|
|
31,066 |
|
|
|
|
|
|
|
198,877 |
|
|
|
131,822 |
|
|
|
|
|
Oil sales |
|
31,742 |
|
|
|
31,886 |
|
|
|
|
|
|
|
75,595 |
|
|
|
114,262 |
|
|
|
|
|
Total oil and gas sales, as reported |
$ |
304,477 |
|
|
$ |
252,065 |
|
|
|
21 |
% |
|
$ |
738,570 |
|
|
$ |
835,601 |
|
|
|
-12 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative fair value
income (loss), as reported: |
$ |
64,556 |
|
|
$ |
202,004 |
|
|
|
|
|
|
$ |
(11,334 |
) |
|
$ |
290,052 |
|
|
|
|
|
Cash settlements on
derivative financial instruments – (gain) loss: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas |
|
(35,822 |
) |
|
|
(80,675 |
) |
|
|
|
|
|
|
(205,985 |
) |
|
|
(223,603 |
) |
|
|
|
|
NGLs |
|
(8,514 |
) |
|
|
(16,047 |
) |
|
|
|
|
|
|
(25,395 |
) |
|
|
(31,608 |
) |
|
|
|
|
Crude Oil |
|
(8,777 |
) |
|
|
(41,207 |
) |
|
|
|
|
|
|
(29,277 |
) |
|
|
(105,434 |
) |
|
|
|
|
Total change in fair
value related to derivatives prior to settlement, a non-GAAP
measure |
$ |
11,443 |
|
|
$ |
64,075 |
|
|
|
|
|
|
$ |
(271,991 |
) |
|
$ |
(70,593 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation, gathering,
processing and compression components: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas |
$ |
99,465 |
|
|
$ |
87,886 |
|
|
|
|
|
|
$ |
288,355 |
|
|
$ |
247,744 |
|
|
|
|
|
NGLs |
|
39,299 |
|
|
|
11,748 |
|
|
|
|
|
|
|
112,516 |
|
|
|
36,514 |
|
|
|
|
|
Total transportation, gathering, processing and
compression, as reported |
$ |
138,764 |
|
|
$ |
99,634 |
|
|
|
|
|
|
$ |
400,871 |
|
|
$ |
284,258 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, NGL and oil
sales, including cash-settled derivatives: (c) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales |
$ |
233,298 |
|
|
$ |
269,788 |
|
|
|
|
|
|
$ |
670,083 |
|
|
$ |
813,120 |
|
|
|
|
|
NGL sales |
|
83,773 |
|
|
|
47,113 |
|
|
|
|
|
|
|
224,272 |
|
|
|
163,430 |
|
|
|
|
|
Oil sales |
|
40,519 |
|
|
|
73,093 |
|
|
|
|
|
|
|
104,872 |
|
|
|
219,696 |
|
|
|
|
|
Total |
$ |
357,590 |
|
|
$ |
389,994 |
|
|
|
-8 |
% |
|
|
999,227 |
|
|
|
1,196,246 |
|
|
|
-16 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production of oil and gas
during the periods (a): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mcf) |
|
93,466,385 |
|
|
|
97,273,739 |
|
|
|
-4 |
% |
|
|
261,331,126 |
|
|
|
265,511,105 |
|
|
|
-2 |
% |
NGL (bbl) |
|
6,739,161 |
|
|
|
4,985,092 |
|
|
|
35 |
% |
|
|
19,579,843 |
|
|
|
15,449,495 |
|
|
|
27 |
% |
Oil (bbl) |
|
810,878 |
|
|
|
958,628 |
|
|
|
-15 |
% |
|
|
2,504,757 |
|
|
|
3,187,005 |
|
|
|
-21 |
% |
Gas equivalent (mcfe)
(b) |
|
138,766,619 |
|
|
|
132,936,059 |
|
|
|
4 |
% |
|
|
393,838,726 |
|
|
|
377,330,105 |
|
|
|
4 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production of oil and gas
– average per day (a): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mcf) |
|
1,015,939 |
|
|
|
1,057,323 |
|
|
|
-4 |
% |
|
|
953,763 |
|
|
|
972,568 |
|
|
|
-2 |
% |
NGL (bbl) |
|
73,252 |
|
|
|
54,186 |
|
|
|
35 |
% |
|
|
71,459 |
|
|
|
56,592 |
|
|
|
26 |
% |
Oil (bbl) |
|
8,814 |
|
|
|
10,420 |
|
|
|
-15 |
% |
|
|
9,141 |
|
|
|
11,674 |
|
|
|
-22 |
% |
Gas equivalent (mcfe)
(b) |
|
1,508,333 |
|
|
|
1,444,957 |
|
|
|
4 |
% |
|
|
1,437,368 |
|
|
|
1,382,162 |
|
|
|
4 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices, including
cash-settled hedges that qualify for hedge accounting before third
party transportation costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mcf) |
$ |
2.11 |
|
|
$ |
1.94 |
|
|
|
9 |
% |
|
$ |
1.78 |
|
|
$ |
2.22 |
|
|
|
-20 |
% |
NGL (bbl) |
$ |
11.17 |
|
|
$ |
6.23 |
|
|
|
79 |
% |
|
$ |
10.16 |
|
|
$ |
8.53 |
|
|
|
19 |
% |
Oil (bbl) |
$ |
39.15 |
|
|
$ |
33.26 |
|
|
|
18 |
% |
|
$ |
30.18 |
|
|
$ |
35.85 |
|
|
|
-16 |
% |
Gas equivalent (mcfe)
(b) |
$ |
2.19 |
|
|
$ |
1.89 |
|
|
|
16 |
% |
|
$ |
1.88 |
|
|
$ |
2.21 |
|
|
|
-15 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices, including
cash-settled hedges and derivatives before third party
transportation costs: (c) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mcf) |
$ |
2.50 |
|
|
$ |
2.77 |
|
|
|
-10 |
% |
|
$ |
2.56 |
|
|
$ |
3.06 |
|
|
|
-16 |
% |
NGL (bbl) |
$ |
12.43 |
|
|
$ |
9.45 |
|
|
|
32 |
% |
|
$ |
11.45 |
|
|
$ |
10.58 |
|
|
|
8 |
% |
Oil (bbl) |
$ |
49.97 |
|
|
$ |
76.25 |
|
|
|
-34 |
% |
|
$ |
41.87 |
|
|
$ |
68.93 |
|
|
|
-39 |
% |
Gas equivalent (mcfe)
(b) |
$ |
2.58 |
|
|
$ |
2.93 |
|
|
|
-12 |
% |
|
$ |
2.54 |
|
|
$ |
3.17 |
|
|
|
-20 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices, including
cash-settled hedges and derivatives: (d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mcf) |
$ |
1.43 |
|
|
$ |
1.87 |
|
|
|
-24 |
% |
|
$ |
1.46 |
|
|
$ |
2.13 |
|
|
|
-31 |
% |
NGL (bbl) |
$ |
6.60 |
|
|
$ |
7.09 |
|
|
|
-7 |
% |
|
$ |
5.71 |
|
|
$ |
8.21 |
|
|
|
-30 |
% |
Oil (bbl) |
$ |
49.97 |
|
|
$ |
76.25 |
|
|
|
-34 |
% |
|
$ |
41.87 |
|
|
$ |
68.93 |
|
|
|
-39 |
% |
Gas equivalent (mcfe)
(b) |
$ |
1.58 |
|
|
$ |
2.18 |
|
|
|
-28 |
% |
|
$ |
1.52 |
|
|
$ |
2.42 |
|
|
|
-37 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation, gathering
and compression expense per mcfe |
$ |
1.00 |
|
|
$ |
0.75 |
|
|
|
33 |
% |
|
$ |
1.02 |
|
|
$ |
0.75 |
|
|
|
35 |
% |
(a) Represents volumes sold regardless of when produced.(b) Oil
and NGLs are converted at the rate of one barrel equals six mcfe
based upon the approximate relative energy content of oil to
natural gas, which is not necessarily indicative of the
relationship of oil and natural gas prices.(c) Excluding third
party transportation, gathering and compression costs.(d) Net of
transportation, gathering, processing and compression costs.
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 September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2016 |
|
|
|
2015 |
|
|
|
% |
|
|
|
2016 |
|
|
|
2015 |
|
|
|
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income taxes,
as reported |
$ |
(55,676 |
) |
|
$ |
(435,729 |
) |
|
|
87 |
% |
|
$ |
(545,848 |
) |
|
$ |
(566,248 |
) |
|
|
-4 |
% |
Adjustment for certain
special items: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss (gain) on sale of assets |
|
2,597 |
|
|
|
681 |
|
|
|
|
|
|
|
7,544 |
|
|
|
(2,053 |
) |
|
|
|
|
(Gain) loss on ARO settlements |
|
6 |
|
|
|
5 |
|
|
|
|
|
|
|
14 |
|
|
|
(23 |
) |
|
|
|
|
Change in fair value related to
derivatives prior to settlement |
|
(11,443 |
) |
|
|
(64,075 |
) |
|
|
|
|
|
|
271,991 |
|
|
|
70,593 |
|
|
|
|
|
Abandonment and impairment of
unproved properties |
|
6,082 |
|
|
|
12,366 |
|
|
|
|
|
|
|
23,769 |
|
|
|
36,187 |
|
|
|
|
|
Loss on early extinguishment of
debt |
|
– |
|
|
|
22,495 |
|
|
|
|
|
|
|
– |
|
|
|
22,495 |
|
|
|
|
|
Impairment of proved property |
|
– |
|
|
|
502,233 |
|
|
|
|
|
|
|
43,040 |
|
|
|
502,233 |
|
|
|
|
|
Lawsuit settlements |
|
120 |
|
|
|
1,278 |
|
|
|
|
|
|
|
1,444 |
|
|
|
2,012 |
|
|
|
|
|
Fees paid to exchange senior
subordinated notes |
|
6,600 |
|
|
|
– |
|
|
|
|
|
|
|
6,600 |
|
|
|
– |
|
|
|
|
|
DEP penalty |
|
– |
|
|
|
– |
|
|
|
|
|
|
|
– |
|
|
|
2,500 |
|
|
|
|
|
Memorial merger expenses |
|
33,791 |
|
|
|
– |
|
|
|
|
|
|
|
36,412 |
|
|
|
– |
|
|
|
|
|
Termination costs |
|
136 |
|
|
|
(76 |
) |
|
|
|
|
|
|
303 |
|
|
|
4,570 |
|
|
|
|
|
Termination costs – non-cash
stock-based compensation |
|
– |
|
|
|
(1 |
) |
|
|
|
|
|
|
– |
|
|
|
1,720 |
|
|
|
|
|
Brokered natural gas and marketing
– non-cash stock-based compensation |
|
455 |
|
|
|
618 |
|
|
|
|
|
|
|
1,349 |
|
|
|
1,743 |
|
|
|
|
|
Direct operating – non-cash
stock-based compensation |
|
497 |
|
|
|
609 |
|
|
|
|
|
|
|
1,781 |
|
|
|
2,149 |
|
|
|
|
|
Exploration expenses – non-cash
stock-based compensation |
|
608 |
|
|
|
688 |
|
|
|
|
|
|
|
1,669 |
|
|
|
2,171 |
|
|
|
|
|
General & administrative –
non-cash stock-based compensation |
|
11,126 |
|
|
|
11,512 |
|
|
|
|
|
|
|
37,682 |
|
|
|
38,545 |
|
|
|
|
|
Deferred compensation plan –
non-cash adjustment |
|
(11,636 |
) |
|
|
(43,705 |
) |
|
|
|
|
|
|
30,166 |
|
|
|
(56,611 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before
income taxes, as adjusted |
|
(16,737 |
) |
|
|
8,899 |
|
|
|
NM |
|
|
|
(82,084 |
) |
|
|
61,983 |
|
|
|
NM |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense, as
adjusted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
– |
|
|
|
– |
|
|
|
|
|
|
|
– |
|
|
|
– |
|
|
|
|
|
Deferred (a) |
|
(6,367 |
) |
|
|
3,436 |
|
|
|
|
|
|
|
(31,333 |
) |
|
|
23,346 |
|
|
|
|
|
Net (loss) income excluding certain items, a
non-GAAP measure |
$ |
(10,370 |
) |
|
$ |
5,463 |
|
|
|
NM |
|
|
$ |
(50,751 |
) |
|
$ |
38,637 |
|
|
|
NM |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-GAAP (loss) income per
common share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
$ |
(0.06 |
) |
|
$ |
0.03 |
|
|
|
NM |
|
|
$ |
(0.30 |
) |
|
$ |
0.23 |
|
|
|
NM |
|
Diluted |
$ |
(0.06 |
) |
|
$ |
0.03 |
|
|
|
NM |
|
|
$ |
(0.30 |
) |
|
$ |
0.23 |
|
|
|
NM |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-GAAP diluted shares
outstanding, if dilutive |
|
180,683 |
|
|
|
166,517 |
|
|
|
|
|
|
|
171,571 |
|
|
|
166,685 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Deferred taxes are estimated to be approximately 38%.
NM = Not meaningful
RANGE RESOURCES CORPORATION
HEDGING POSITION AS OF October 21,
2016(Unaudited) –
|
|
|
|
|
Daily Volume |
|
|
|
Hedge Price |
|
|
Gas |
|
|
|
|
|
|
|
|
|
|
4Q 2016 Swaps (2) |
|
|
|
901,739 Mmbtu |
|
|
|
$ |
3.32 |
|
|
|
4Q 2016 Puts (1)
(2) |
|
|
|
218,478 Mmbtu |
|
|
|
$ |
3.20 |
|
|
|
4Q 2016 Collars
(2) |
|
|
|
32,609
Mmbtu |
|
|
|
$4.00 x $4.71 |
|
|
|
|
|
|
|
|
|
|
|
|
|
2017 Swaps (2) |
|
|
|
610,691 Mmbtu |
|
|
|
$ |
3.18 |
|
|
|
2017 Puts (1) (2) |
|
|
|
175,890 Mmbtu |
|
|
|
$ |
3.17 |
|
|
|
2017 Collars (2) |
|
|
|
34,521
Mmbtu |
|
|
|
$4.00 x $5.06 |
|
|
|
|
|
|
|
|
|
|
|
|
|
2018 Swaps |
|
|
|
130,000 Mmbtu |
|
|
|
$ |
2.98 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
|
|
|
|
|
|
|
|
4Q 2016 Swaps (2) |
|
|
|
8,640
bbls |
|
|
|
$ |
69.49 |
|
|
|
4Q 2016 Collars
(2) |
|
|
|
848
bbls |
|
|
|
$80.00 x $99.70 |
|
|
|
|
|
|
|
|
|
|
|
|
|
2017 Swaps |
|
|
|
5,666
bbls |
|
|
|
$ |
57.04 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018 Swaps |
|
|
|
750
bbls |
|
|
|
$ |
54.42 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
C2
Ethane |
|
|
|
|
|
|
|
|
|
|
4Q 2016 Swaps (2) |
|
|
|
5,839
bbls |
|
|
|
$0.46/gallon |
|
|
|
|
|
|
|
|
|
|
|
|
|
2017 Swaps |
|
|
|
3,000
bbls |
|
|
|
$0.27/gallon |
|
|
|
|
|
|
|
|
|
|
|
|
|
C3
Propane |
|
|
|
|
|
|
|
|
|
|
4Q 2016 Swaps (2) |
|
|
|
11,142
bbls |
|
|
|
$0.75/gallon |
|
|
|
|
|
|
|
|
|
|
|
|
|
2017 Swaps |
|
|
|
5,500
bbls |
|
|
|
$0.53/gallon |
|
|
|
|
|
|
|
|
|
|
|
|
|
C4 Normal
Butane |
|
|
|
|
|
|
|
|
|
|
4Q 2016 Swaps (2) |
|
|
|
6,071
bbls |
|
|
|
$0.72/gallon |
|
|
|
|
|
|
|
|
|
|
|
|
|
2017 Swaps |
|
|
|
2,500 bbls |
|
|
|
$0.68/gallon |
|
|
|
|
|
|
|
|
|
|
|
|
|
IC4 ISO
Butane |
|
|
|
|
|
|
|
|
|
|
4Q 2016 Swaps (2) |
|
|
|
1,969
bbls |
|
|
|
$1.21/gallon |
|
|
|
|
|
|
|
|
|
|
|
|
|
C5 Natural
Gasoline |
|
|
|
|
|
|
|
|
|
|
4Q 2016 Swaps (2) |
|
|
|
8,142
bbls |
|
|
|
$1.36/gallon |
|
|
|
|
|
|
|
|
|
|
|
|
|
2017 Swaps |
|
|
|
2,750
bbls |
|
|
|
$01.01/gallon |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Net of deferred premiums
(2) Includes derivative instruments assumed in connection with
the Memorial Merger
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:
Matt Pitzarella, Director of Corporate Communications
724-873-3224
mpitzarella@rangeresources.com
www.rangeresources.com
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