RANGE RESOURCES CORPORATION (NYSE:RRC) today
announced its first quarter 2017 financial results.
Highlights –
- First quarter GAAP net income reached $170 million, or $0.69
per diluted share, compared to a net loss of $94 million, or $0.56
per share in the prior-year quarter
- First quarter cash margins improved to $1.47 per mcfe, compared
to $0.77 per mcfe in the prior-year quarter, an improvement of
91%
- Cash flow from operations before changes in working capital, a
non-GAAP measure, reached $258 million, $1.05 per diluted share,
compared to $99 million, $0.59 per diluted share, in first quarter
2016
- Record production of 1.93 Bcfe per day, an increase of 40%
compared to the prior-year quarter
- Total unit costs continued to decline, with first quarter 2017
costs of $2.57 per mcfe, compared to $2.71 in the previous year
quarter, an improvement of 5%
- Super-rich pad in northwestern Washington County, PA averages
31.4 Mmcfe per day per well
- North Louisiana well costs continue to improve, currently at
$7.4 million per well, compared to $7.7 million in the previous
quarter and approximately $8.7 million when the properties were
acquired
Commenting, Jeff Ventura, the Company’s CEO
said, “The first quarter of 2017 was an excellent quarter for
Range. First quarter cash margins improved to $1.47 per mcfe,
compared to $0.77 per mcfe a year ago. In addition to
improved macroeconomic conditions, margin expansion is being driven
by improving netbacks from better transportation arrangements and a
continued focus on cost and operational improvements throughout the
company. With our extensive drilling inventory combined with
expected increasing demand for natural gas and NGLs over the next
several years, Range is well-positioned to generate shareholder
value for 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 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.
First Quarter 2017
GAAP revenues for the first quarter of 2017
totaled $777 million (134% increase compared to first quarter
2016), GAAP net cash provided from operating activities including
changes in working capital was $226 million (149% increase as
compared to first quarter 2016) and GAAP earnings were $170 million
($0.69 per diluted share) versus a loss of $94 million ($0.56 per
diluted share) in the prior-year quarter. First quarter 2017
included $166 million in derivative gains due to decreased
commodity prices, compared to an $87 million gain in 2016. First
quarter 2017 results also included a $23 million gain on sale of
assets, while first quarter 2016 included a loss of $1.6 million.
A $43 million impairment of proved property was also recorded
in first quarter
2016.
Non-GAAP revenues for first quarter 2017 totaled $607 million (71%
increase compared to first quarter 2016) and cash flow from
operations before changes in working capital, a non-GAAP measure,
reached $258 million, compared to $99 million in first quarter
2016. Adjusted net income comparable to analysts’ estimates,
a non-GAAP measure, was $61 million ($0.25 per diluted share)
compared to a loss of $17 million ($0.10 per diluted share) for
first quarter 2016.
The Company’s total unit costs were lower than
the previous year quarter, with decreases in all categories, except
for a $0.02 per mcfe increase in transportation, gathering,
processing and compression expense and production and ad valorem
taxes, which were unchanged from the prior-year quarter.
Increased transportation expenses are offset by higher realized
prices, as products are moved to more favorable markets with higher
prices, thereby resulting in significantly increased cash margins
from the previous year.
Expenses |
|
1Q 2017 (per
mcfe) |
|
1Q 2016(per
mcfe) |
|
|
Increase (Decrease) |
|
|
|
|
|
|
|
|
|
Direct operating |
|
$ |
0.16 |
|
$ |
0.19 |
|
|
(16 |
%) |
|
Transportation,
gathering, processing and compression |
|
|
1.02 |
|
|
1.00 |
|
|
2 |
% |
|
Production and ad
valorem taxes |
|
|
0.05 |
|
|
0.05 |
|
|
- |
% |
|
General and
administrative |
|
|
0.21 |
|
|
0.23 |
|
|
(9 |
%) |
|
Interest expense |
|
|
0.27 |
|
|
0.30 |
|
|
(10 |
%) |
|
Total
cash unit costs(a) |
|
|
1.71 |
|
|
1.76 |
|
|
(3 |
%) |
|
Depletion, depreciation
and amortization |
|
|
0.86 |
|
|
0.96 |
|
|
(10 |
%) |
|
Total
unit costs(a) |
|
$ |
2.57 |
|
$ |
2.71 |
|
|
(5 |
%) |
|
|
|
|
|
|
|
|
|
|
(a) Totals may not add due to rounding.
First quarter 2017 natural gas, NGLs and oil price realizations
(including the impact of cash-settled hedges and derivative
settlements which correspond to analysts’ estimates) averaged $3.19
per mcfe, a 26% increase 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 first
quarter 2017 were: natural gas – 1,292 Mmcf per day ($3.26
per mcf), NGLs – 94,853 barrels per day ($14.49 per barrel) and
crude oil and condensate – 11,837 barrels per day ($49.50 per
barrel).
- The average Company natural gas price differential including
the impact of basis hedges for first quarter 2017 was a positive
$0.01 per mcf, compared to a negative ($0.31) in first quarter
2016. The first quarter average natural gas price, before all
hedging settlements, was $3.19 per mcf as compared to $1.68 per mcf
in the prior year.
- Pre-hedge NGL realizations improved to 31% of West Texas
Intermediate (“WTI”) in first quarter 2017, compared to 25% of WTI
in the previous year. Total NGL pricing per barrel including
ethane and processing expenses after realized cash-settled hedging
improved to $14.49 for first quarter 2017 compared to $10.22 per
barrel in the prior year.
- Crude oil and condensate price realizations, before realized
hedges, for the first quarter 2017 averaged $46.97 per barrel, or
$4.84 below WTI, compared to $13.56 below WTI in the prior
year. Hedging added $2.53 per barrel in first quarter
2017.
Capital Expenditures
First quarter 2017 drilling expenditures of $228
million funded the drilling of 54 (53 net) wells. A 100%
success rate was achieved. In addition, during the quarter,
$25 million was incurred on acreage purchases, $1.5 million on gas
gathering systems and $8 million on exploration expense.
Range is on target with its $1.15 billion capital budget for
2017.
Financial Position and
Liquidity
The Company’s existing $3 billion borrowing base
and $2 billion commitment amount under its $4 billion bank credit
facility were unanimously reaffirmed by its 29 lenders with no
changes to the financial covenants. The credit facility
matures on October 16, 2019 and is subject to annual
redeterminations, which are required to be completed by May of each
year.
At March 31, 2017, Range had total debt
outstanding of $3.77 billion, before amortization of debt issuance
costs and premium, consisting of $2.88 billion in senior notes,
$846 million in bank debt and $49 million in senior subordinated
notes. The outstanding bank debt of $846 million combined
with $280 million of undrawn letters of credit provides committed
liquidity of $874 million from borrowing capacity available under
the facility.
Operational Discussion
Range has updated its investor presentation.
Please see www.rangeresources.com under the Investors tab, “Company
Presentations” area, for the presentation entitled, “Company
Presentation – April 24, 2017”.
The table below summarizes first quarter
activity and the number of wells expected to be turned in line
(TIL) for the remainder of 2017:
|
|
2017 |
|
|
Wells TIL - First Quarter |
Remaining Wells to Sales |
Planned Total Wells to Sales |
Super-Rich Area |
|
6 |
33 |
39 |
Wet Area |
|
10 |
35 |
45 |
Dry- SW |
|
6 |
24 |
30 |
Dry- NE |
|
— |
2 |
2 |
Total
Marcellus |
|
22 |
94 |
116 |
|
|
|
|
|
Upper Red |
|
19 |
15 |
34 |
Lower Red |
|
5 |
8 |
13 |
Pink |
|
3 |
3 |
6 |
Extension Area |
|
— |
3 |
3 |
Total N.
LA. |
|
27 |
29 |
56 |
|
|
|
|
|
Company
Total |
|
49 |
123 |
172 |
|
|
|
|
|
Appalachia Division
In order to streamline operations and reduce
costs, the Southern Marcellus Division and Northern Marcellus
Division have been combined, and going forward will be referred to
as the Appalachia Division. Production for first quarter 2017
averaged 1,503 net Mmcfe per day, a 13% increase over the prior
year. The southern Marcellus properties averaged 1,341 net
Mmcfe per day during the quarter, a 22% increase over the prior
year. The northern Marcellus properties averaged 162 net Mmcf
per day during the quarter, a 31% decrease over the prior year, or
a 23% decrease over the prior year when adjusted for asset
sales.
The division brought on line 22 wells in the
first quarter, six in the super-rich area, 10 in the wet area and
six in the southwest dry area. The team continues to improve
capital efficiency by drilling longer laterals, lowering costs and
increasing recoveries with approximately one-third of 2017 wells
expected to be drilled from existing pads. Several recent
examples are listed below, which have continued to drive lower
normalized well costs and reduce operating costs per mcfe.
- Daily lateral footage drilled has increased by 67% compared to
the previous year
- Drilling cost per lateral foot in first quarter 2017 decreased
by 30% compared to the previous year
- One-third of wells brought on line in 2017 are expected to be
drilled on existing pads, with expected savings of $200,000 to
$500,000 per well
- Average lateral lengths drilled in 2017 are expected to
approach 9,000 feet
During the first quarter, the division drilled
and completed four super-rich wells from a pad located in a lightly
drilled area, near the planned Harmon Creek processing plant in
northwestern Washington County. Due to the high initial
production rates, only two of the wells were brought on line.
The two wells averaged a 24-hour rate to sales of 31.4 Mmcfe per
day for each well, or a combined rate of 62.8 Mmcfe per day from an
average lateral length of 10,772 feet with 54 stages. The
remaining two wells on the pad will be brought on line after the
first two wells decline, when capacity in the gathering system is
available.
In addition to the planned Harmon Creek complex
mentioned above, the Houston processing plant is also undergoing an
upgrade to support Range’s future growth. In the second
quarter, operations are beginning for the removal of the original
Houston I plant that is being replaced and upgraded with a 200 Mmcf
capacity cryogenic plant, which will increase processing capacity
by 170 Mmcf per day. There is additional maintenance and
numerous upgrades being performed during this downtime. This
will impact Range’s second quarter production, and is reflected in
second quarter production guidance.
North Louisiana Division
Production for the division in the first quarter
of 2017 averaged approximately 397 net Mmcfe per day. The
division continues to lower drilling and completion costs of a
typical 7,500 foot lateral well in Terryville. The Company
now expects these wells will cost approximately $7.4 million, which
includes a forecasted 5% to 25% increase in some service
costs. This represents a cost reduction of $300,000 from the
previous quarter, and a reduction of $1.3 million since Range
acquired the properties in September 2016. The lower cost
significantly improves well economics in Terryville, and adds
potential locations across the field. The savings realized
from the reduction in Terryville well costs are expected to be used
to fund increased seismic, research and development costs, or
additional wells.
As part of the overall cost reduction, Range has
optimized facility designs, which has the effect of lower initial
rates, but flatter declines and overall improved economics as a
result of the lower costs. The most recent cost reduction of
$300,000 has resulted from several factors including:
- Reduced day rates on drilling contracts
- Reduced casing costs by utilizing Range’s supply chain
management team
- Reduced mobilization time
- Increased number of stages pumped per day, currently almost
twice the previous rate
- Reduced coil tubing and flow back equipment cost
The division brought on line 27 wells in the
first quarter. The locations for this group of wells were
chosen by the previous operator and 18 of the wells had already
been drilled prior to Range acquiring the assets last
September. Completing this large backlog of wells, many of
which had been waiting on completion for almost a year, required
the shut-in of approximately 40 Mmcfe per day of offset production
during the first quarter. Offset wells are shut-in to reduce
the effect of frac hits, and we expect production to return
throughout the remainder of the year. Going forward, the
Company is planning a more balanced pace of drilling and completion
activity to minimize the impact on offset production and continue
driving operational efficiencies. Since taking over
operations, Range has also revised production methods in accordance
with Range’s safety and facilities protocol, which reduces 2017
production rates by approximately 30 Mmcfe per day. This
facility change results in a production profile that has a flatter
decline and does not change expected ultimate recovery. The
Company expects to bring to sales 29 additional wells during the
remainder of the year.
Results continue to be encouraging from two of
the extension wells announced last quarter. Each of the two
wells, located in separate Terryville sized fault blocks, with one
well located to the east and one well to the west of Vernon field,
has cumulative production to date of approximately one Bcfe
each. As a result, plans are underway to offset each well
with another horizontal well.
Marketing and
Transportation
Range has assembled a diversified transportation
and marketing portfolio across all of its products. Many of
these transportation projects and marketing contracts were years in
the making, only coming to fruition in the last twelve
months. These recent additions, including Mariner East, Gulf
Markets Expansion and recent condensate sales agreements have
significantly improved the Company’s realizations in 2017 for
natural gas, NGLs and condensate. As part of that continued
development, Range will be adding to its gathering capacity in
southwestern Pennsylvania during the second and third quarters of
2017. The timing of this added gathering capacity fits well
with anticipated natural gas long-haul transportation expected to
come on line later in 2017. Range’s long-term marketing plans
and firm transportation portfolio will allow Range to sell natural
gas into improving Appalachia markets as well as to growing Gulf
Coast, Southwest and Midwest markets. As a result of the
increased gathering capacity, the Company expects transportation,
gathering, processing and compression expense to increase in second
quarter 2017 before trending down over the course of 2018 as the
new gathering and transportation capacity is filled. In
addition to allowing the Company to optimize its long-haul firm
transportation commitments, this gathering capacity also provides
Range added flexibility in allocating future growth capital across
the liquids-rich and dry areas of southwestern
Pennsylvania.
Guidance – 2017
Production per day Guidance
Production for the second quarter of 2017 is
expected to be approximately 1.93 Bcfe per day with 30% to 32%
liquids.
Production growth for the full year of 2017 is
unchanged at 33% to 35%.
2Q 2017 Expense Guidance
Direct
operating expense: |
$0.17 -
$0.18 per mcfe |
Transportation, gathering, processing and compression
expense: |
$1.04 -
$1.08 per mcfe |
Production tax expense: |
$0.05 -
$0.06 per mcfe |
Exploration expense: |
$12.0 -
$13.0 million |
Unproved
property impairment expense: |
$4.0 -
$6.0 million |
G&A
expense: |
$0.21 -
$0.23 per mcfe |
Interest
expense: |
$0.26 -
$0.28 per mcfe |
DD&A
expense: |
$0.87 -
$0.89 per mcfe |
Net
brokered gas marketing expense: |
~$3.0
million |
2017 Differentials
Based on current market pricing indications, Range expects to
receive the following pre-hedge differentials for its production in
2017.
Natural Gas: |
NYMEX minus $0.30 |
Natural Gas Liquids
(including ethane): |
28% - 30% of WTI |
Oil/Condensate: |
WTI minus $5.00 to
$6.00 |
Hedging Status
Range hedges portions of its expected future
production volumes to increase the predictability of cash flow and
to help maintain a strong, flexible financial position. Range
currently has over 75% of its expected remaining 2017 natural gas
production hedged at a weighted average floor price of $3.22 per
mcf, and over one Bcf per day of first quarter 2018 production
hedged at $3.43. Similarly, Range has hedged over 65% of its
remaining 2017 projected crude oil production at a floor price of
approximately $56.00 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 March 31,
2017 was a loss of $20.4 million, compared to a gain of $11.8
million at December 31, 2016.
Conference Call InformationA
conference call to review the financial results is scheduled on
Tuesday, April 25 at 9:00 a.m. ET. To participate in the call,
please dial 866-900-7525 and provide conference code 89127307 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 May 25.
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 natural gas, NGL and oil
producer with operations focused in stacked-pay projects in the
Appalachian Basin and North Louisiana. The Company pursues an
organic growth strategy targeting high return, low-cost projects
within its large inventory of low risk development drilling
opportunities. The Company is headquartered in Fort Worth, Texas.
More information about Range can be found at
www.rangeresources.com.
All statements, except for statements of
historical fact, made in this release regarding activities, events
or developments the Company expects, believes or anticipates will
or may occur in the future, such as those regarding 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.
2017-07SOURCE: Range Resources
Corporation
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 March 31, |
|
|
2017 |
|
|
|
2016 |
|
|
|
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues and other
income: |
|
|
|
|
|
|
|
|
|
|
|
Natural
gas, NGLs and oil sales (a) |
$ |
559,450 |
|
|
$ |
209,487 |
|
|
|
|
|
Derivative fair value income |
|
165,557 |
|
|
|
86,908 |
|
|
|
|
|
Brokered
natural gas, marketing and other (b) |
|
51,581 |
|
|
|
34,858 |
|
|
|
|
|
ARO loss
(b) |
|
— |
|
|
|
(2 |
) |
|
|
|
|
Other
(b) |
|
67 |
|
|
|
162 |
|
|
|
|
|
Total
revenues and other income |
|
776,655 |
|
|
|
331,413 |
|
|
|
134 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
Costs and
expenses: |
|
|
|
|
|
|
|
|
|
|
|
Direct
operating |
|
27,499 |
|
|
|
23,466 |
|
|
|
|
|
Direct
operating – non-cash stock-based compensation (c) |
|
524 |
|
|
|
588 |
|
|
|
|
|
Transportation, gathering, processing and compression |
|
177,648 |
|
|
|
125,263 |
|
|
|
|
|
Production and ad valorem taxes |
|
9,163 |
|
|
|
5,887 |
|
|
|
|
|
Brokered
natural gas and marketing |
|
53,287 |
|
|
|
36,042 |
|
|
|
|
|
Brokered
natural gas and marketing – non-cash stock-based
compensation (c) |
|
263 |
|
|
|
516 |
|
|
|
|
|
Exploration |
|
7,997 |
|
|
|
4,223 |
|
|
|
|
|
Exploration – non-cash stock-based compensation (c) |
|
507 |
|
|
|
690 |
|
|
|
|
|
Abandonment and impairment of unproved properties |
|
4,420 |
|
|
|
10,628 |
|
|
|
|
|
General
and administrative |
|
35,955 |
|
|
|
28,423 |
|
|
|
|
|
General
and administrative – non-cash stock-based compensation
(c) |
|
10,918 |
|
|
|
11,113 |
|
|
|
|
|
General
and administrative – lawsuit settlements |
|
623 |
|
|
|
921 |
|
|
|
|
|
General
and administrative – bad debt expense |
|
— |
|
|
|
200 |
|
|
|
|
|
Termination costs |
|
2,450 |
|
|
|
162 |
|
|
|
|
|
Termination costs – non-cash stock-based compensation (c) |
|
1,742 |
|
|
|
— |
|
|
|
|
|
Deferred
compensation plan (d) |
|
(13,169 |
) |
|
|
16,056 |
|
|
|
|
|
Interest
expense |
|
47,101 |
|
|
|
37,739 |
|
|
|
|
|
Depletion, depreciation and amortization |
|
149,821 |
|
|
|
120,561 |
|
|
|
|
|
Impairment of proved properties and other assets |
|
— |
|
|
|
43,040 |
|
|
|
|
|
(Gain)
loss on sale of assets |
|
(22,600 |
) |
|
|
1,643 |
|
|
|
|
|
Total
costs and expenses |
|
494,149 |
|
|
|
467,161 |
|
|
|
6 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before
income taxes |
|
282,506 |
|
|
|
(135,748 |
) |
|
|
308 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense
(benefit): |
|
|
|
|
|
|
|
|
|
|
|
Current |
|
— |
|
|
|
— |
|
|
|
|
|
Deferred |
|
112,395 |
|
|
|
(41,976 |
) |
|
|
|
|
|
|
112,395 |
|
|
|
(41,976 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
$ |
170,111 |
|
|
$ |
(93,772 |
) |
|
|
281 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
(Loss) Per Common Share: |
|
|
|
|
|
|
|
|
|
|
|
Basic |
$ |
0.69 |
|
|
$ |
(0.56 |
) |
|
|
|
|
Diluted |
$ |
0.69 |
|
|
$ |
(0.56 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common
shares outstanding, as reported: |
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
244,652 |
|
|
|
166,803 |
|
|
|
47 |
% |
Diluted |
|
244,803 |
|
|
|
166,803 |
|
|
|
47 |
% |
(a) See separate natural gas, NGLs and oil sales
information table.(b) Included in Brokered natural gas,
marketing and other revenues in the 10-Q.(c) Costs associated
with stock compensation and restricted stock amortization, which
have been reflected in the categories associated
with the direct personnel costs, which are combined with the
cash costs in the 10-Q.(d) Reflects the change in market
value of the vested Company stock held in the deferred compensation
plan.
RANGE RESOURCES CORPORATION |
|
|
|
BALANCE
SHEETS |
|
|
|
|
|
|
|
(In thousands) |
|
March
31, |
|
|
|
December 31, |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
(Unaudited) |
|
|
|
(Audited) |
|
Assets |
|
|
|
|
|
|
|
Current
assets |
$ |
267,083 |
|
|
$ |
268,605 |
|
Derivative assets |
|
46,245 |
|
|
|
13,483 |
|
Goodwill |
|
1,654,292 |
|
|
|
1,654,292 |
|
Natural
gas and oil properties, successful efforts method |
|
9,359,864 |
|
|
|
9,256,337 |
|
Transportation and field assets |
|
16,749 |
|
|
|
16,873 |
|
Other |
|
77,512 |
|
|
|
72,655 |
|
|
$ |
11,421,745 |
|
|
$ |
11,282,245 |
|
|
|
|
|
|
|
|
|
Liabilities and
Stockholders’ Equity |
|
|
|
|
|
|
|
Current
liabilities |
$ |
568,096 |
|
|
$ |
530,373 |
|
Asset
retirement obligations |
|
7,271 |
|
|
|
7,271 |
|
Derivative liabilities |
|
55,713 |
|
|
|
165,009 |
|
|
|
|
|
|
|
|
|
Bank
debt |
|
841,188 |
|
|
|
876,428 |
|
Senior
notes |
|
2,849,088 |
|
|
|
2,848,591 |
|
Senior
subordinated notes |
|
48,519 |
|
|
|
48,498 |
|
Total
debt |
|
3,738,795 |
|
|
|
3,773,517 |
|
|
|
|
|
|
|
|
|
Deferred
tax liability |
|
1,055,737 |
|
|
|
943,343 |
|
Derivative liabilities |
|
1,515 |
|
|
|
24,491 |
|
Deferred
compensation liability |
|
110,455 |
|
|
|
119,231 |
|
Asset
retirement obligations and other liabilities |
|
301,687 |
|
|
|
310,642 |
|
|
|
|
|
|
|
|
|
Common
stock and retained earnings |
|
5,583,530 |
|
|
|
5,409,577 |
|
Common
stock held in treasury stock |
|
(1,054 |
) |
|
|
(1,209 |
) |
Total
stockholders’ equity |
|
5,582,476 |
|
|
|
5,408,368 |
|
|
$ |
11,421,745 |
|
|
$ |
11,282,245 |
|
RECONCILIATION
OF TOTAL REVENUES AND OTHER INCOME TO TOTAL REVENUE EXCLUDING
CERTAIN ITEMS, a non-GAAP measure |
|
(Unaudited, in
thousands) |
|
|
Three Months Ended March 31, |
|
|
2017 |
|
|
|
2016 |
|
|
|
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues and
other income, as reported |
$ |
776,655 |
|
|
$ |
331,413 |
|
|
|
134 |
% |
Adjustment for certain
special items: |
|
|
|
|
|
|
|
|
|
|
|
Total
change in fair value related to derivatives prior to settlement
(gain) loss |
|
(169,738 |
) |
|
|
22,558 |
|
|
|
|
|
ARO
settlement (gain) loss |
|
— |
|
|
|
2 |
|
|
|
|
|
Total revenues, as
adjusted, non-GAAP |
$ |
606,917 |
|
|
$ |
353,973 |
|
|
|
71 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
RANGE RESOURCES CORPORATION |
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM
OPERATING ACTIVITIES |
|
|
|
|
|
|
|
(Unaudited in
thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2017 |
|
|
|
|
2016 |
|
|
|
|
|
|
|
|
|
Net income (loss) |
$ |
170,111 |
|
|
|
$ |
(93,772 |
) |
Adjustments to
reconcile net cash provided from continuing operations: |
|
|
|
|
|
|
|
|
Deferred
income tax expense (benefit) |
|
112,395 |
|
|
|
|
(41,976 |
) |
Depletion, depreciation, amortization and impairment |
|
149,821 |
|
|
|
|
163,601 |
|
Abandonment and impairment of unproved properties |
|
4,420 |
|
|
|
|
10,628 |
|
Derivative fair value (income) |
|
(165,557 |
) |
|
|
|
(86,908 |
) |
Cash
settlements on derivative financial instruments that do not qualify
for hedge accounting |
|
(4,181 |
) |
|
|
|
109,466 |
|
Allowance
for bad debts |
|
— |
|
|
|
|
200 |
|
Amortization of deferred issuance costs, loss on extinguishment of
debt and other |
|
1,310 |
|
|
|
|
1,707 |
|
Deferred
and stock-based compensation |
|
962 |
|
|
|
|
29,128 |
|
(Gain)
loss on sale of assets and other |
|
(22,600 |
) |
|
|
|
1,643 |
|
|
|
|
|
|
|
|
|
|
Changes
in working capital: |
|
|
|
|
|
|
|
|
Accounts
receivable |
|
(4,690 |
) |
|
|
|
18,752 |
|
Inventory
and other |
|
2,868 |
|
|
|
|
5,333 |
|
Accounts
payable |
|
24,384 |
|
|
|
|
11,922 |
|
Accrued
liabilities and other |
|
(43,381 |
) |
|
|
|
(38,939 |
) |
Net
changes in working capital |
|
(20,819 |
) |
|
|
|
(2,932 |
) |
Net cash
provided from operating activities |
$ |
225,862 |
|
|
|
$ |
90,785 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 March 31, |
|
|
2017 |
|
|
|
|
2016 |
|
Net cash provided from
operating activities, as reported |
$ |
225,862 |
|
|
|
$ |
90,785 |
|
Net
changes in working capital |
|
20,819 |
|
|
|
|
2,932 |
|
Exploration expense |
|
7,997 |
|
|
|
|
4,223 |
|
Lawsuit
settlements |
|
623 |
|
|
|
|
921 |
|
Termination costs |
|
2,450 |
|
|
|
|
162 |
|
Non-cash
compensation adjustment |
|
291 |
|
|
|
|
(84 |
) |
Cash flow from
operations before changes in working capital – non-GAAP
measure |
$ |
258,042 |
|
|
|
$ |
98,939 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ADJUSTED
WEIGHTED AVERAGE SHARES OUTSTANDING |
|
|
|
|
|
|
|
(Unaudited, in
thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2017 |
|
|
|
|
2016 |
|
Basic: |
|
|
|
|
|
|
|
Weighted average shares
outstanding |
|
247,390 |
|
|
|
|
169,584 |
|
Stock held by deferred
compensation plan |
|
(2,738 |
) |
|
|
|
(2,781 |
) |
Adjusted
basic |
|
244,652 |
|
|
|
|
166,803 |
|
|
|
|
|
|
|
|
|
|
Dilutive: |
|
|
|
|
|
|
|
|
Weighted average shares
outstanding |
|
247,390 |
|
|
|
|
169,584 |
|
Dilutive stock options
under treasury method |
|
(2,587 |
) |
|
|
|
(2,781 |
) |
Adjusted
dilutive |
|
244,803 |
|
|
|
|
166,803 |
|
|
|
|
|
|
|
|
|
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 March 31, |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
% |
|
Natural gas, NGL and
oil sales components: |
|
|
|
|
|
|
|
|
|
|
|
Natural
gas sales |
$ |
371,352 |
|
|
$ |
142,435 |
|
|
|
|
|
NGL
sales |
|
138,063 |
|
|
|
50,162 |
|
|
|
|
|
Oil
sales |
|
50,035 |
|
|
|
16,890 |
|
|
|
|
|
Total oil and gas
sales, as reported |
$ |
559,450 |
|
|
$ |
209,487 |
|
|
|
167 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
Derivative fair value
income (loss), as reported: |
$ |
165,557 |
|
|
$ |
86,908 |
|
|
|
|
|
Cash settlements on
derivative financial instruments – (gain) loss: |
|
|
|
|
|
|
|
|
|
|
|
Natural
gas |
|
(7,455 |
) |
|
|
(85,515 |
) |
|
|
|
|
NGLs |
|
14,333 |
|
|
|
(10,878 |
) |
|
|
|
|
Crude
Oil |
|
(2,697 |
) |
|
|
(13,073 |
) |
|
|
|
|
Total change in fair
value related to derivatives prior to settlement, a non-GAAP
measure |
$ |
169,738 |
|
|
$ |
(22,558 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation,
gathering, processing and compression components: |
|
|
|
|
|
|
|
|
|
|
|
Natural
gas |
$ |
122,194 |
|
|
$ |
92,592 |
|
|
|
|
|
NGLs |
|
55,454 |
|
|
|
32,671 |
|
|
|
|
|
Total transportation,
gathering, processing and compression, as reported |
$ |
177,648 |
|
|
$ |
125,263 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, NGL and
oil sales, including cash-settled derivatives: (c) |
|
|
|
|
|
|
|
|
|
|
|
Natural
gas sales |
$ |
378,807 |
|
|
$ |
227,950 |
|
|
|
|
|
NGL
sales |
|
123,730 |
|
|
|
61,040 |
|
|
|
|
|
Oil
sales |
|
52,732 |
|
|
|
29,963 |
|
|
|
|
|
Total |
$ |
555,269 |
|
|
$ |
318,953 |
|
|
|
74 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
Production of oil and
gas during the periods (a): |
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (mcf) |
|
116,256,337 |
|
|
|
84,867,370 |
|
|
|
37 |
% |
NGL
(bbl) |
|
8,536,728 |
|
|
|
5,974,734 |
|
|
|
43 |
% |
Oil
(bbl) |
|
1,065,286 |
|
|
|
844,341 |
|
|
|
26 |
% |
Gas equivalent (mcfe)
(b) |
|
173,868,421 |
|
|
|
125,781,820 |
|
|
|
38 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
Production of oil and
gas – average per day (a): |
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (mcf) |
|
1,291,737 |
|
|
|
932,608 |
|
|
|
39 |
% |
NGL
(bbl) |
|
94,853 |
|
|
|
65,656 |
|
|
|
44 |
% |
Oil
(bbl) |
|
11,837 |
|
|
|
9,278 |
|
|
|
28 |
% |
Gas equivalent (mcfe)
(b) |
|
1,931,871 |
|
|
|
1,382,218 |
|
|
|
40 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
Average prices,
including cash-settled hedges that qualify for hedge accounting
before third party transportation costs: |
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (mcf) |
$ |
3.19 |
|
|
$ |
1.68 |
|
|
|
90 |
% |
NGL
(bbl) |
$ |
16.17 |
|
|
$ |
8.40 |
|
|
|
93 |
% |
Oil
(bbl) |
$ |
46.97 |
|
|
$ |
20.00 |
|
|
|
135 |
% |
Gas equivalent (mcfe)
(b) |
$ |
3.22 |
|
|
$ |
1.67 |
|
|
|
93 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
Average prices,
including cash-settled hedges and derivatives before third party
transportation costs: (c) |
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (mcf) |
$ |
3.26 |
|
|
$ |
2.69 |
|
|
|
21 |
% |
NGL
(bbl) |
$ |
14.49 |
|
|
$ |
10.22 |
|
|
|
42 |
% |
Oil
(bbl) |
$ |
49.50 |
|
|
$ |
35.49 |
|
|
|
39 |
% |
Gas equivalent (mcfe)
(b) |
$ |
3.19 |
|
|
$ |
2.54 |
|
|
|
26 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
Average prices,
including cash-settled hedges and derivatives: (d) |
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (mcf) |
$ |
2.21 |
|
|
$ |
1.59 |
|
|
|
38 |
% |
NGL
(bbl) |
$ |
8.00 |
|
|
$ |
4.75 |
|
|
|
68 |
% |
Oil
(bbl) |
$ |
49.50 |
|
|
$ |
35.49 |
|
|
|
39 |
% |
Gas equivalent (mcfe)
(b) |
$ |
2.17 |
|
|
$ |
1.54 |
|
|
|
41 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
Transportation,
gathering and compression expense per mcfe |
$ |
1.02 |
|
|
$ |
1.00 |
|
|
|
3 |
% |
(a) Represents volumes sold regardless of when
produced.(b) Oil and NGLs are converted at the rate of one
barrel equals six mcfe based upon the approximate relative energy
content of oil to natural gas, which is not necessarily indicative
of the relationship of oil and natural gas prices.(c)
Excluding third party transportation, gathering and
compression costs.(d) Net of transportation, gathering,
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 March 31, |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from
operations before income taxes, as reported |
$ |
282,506 |
|
|
$ |
(135,748 |
) |
|
|
308 |
% |
Adjustment for certain
special items: |
|
|
|
|
|
|
|
|
|
|
|
(Gain)
loss on sale of assets |
|
(22,600 |
) |
|
|
1,643 |
|
|
|
|
|
Loss on
ARO settlements |
|
— |
|
|
|
2 |
|
|
|
|
|
Change in
fair value related to derivatives prior to settlement |
|
(169,738 |
) |
|
|
22,558 |
|
|
|
|
|
Abandonment and impairment of unproved properties |
|
4,420 |
|
|
|
10,628 |
|
|
|
|
|
Impairment of proved property |
|
— |
|
|
|
43,040 |
|
|
|
|
|
Lawsuit
settlements |
|
623 |
|
|
|
921 |
|
|
|
|
|
Termination costs |
|
2,450 |
|
|
|
162 |
|
|
|
|
|
Termination costs – non-cash stock-based compensation |
|
1,742 |
|
|
|
— |
|
|
|
|
|
Brokered
natural gas and marketing – non-cash stock-based compensation |
|
263 |
|
|
|
516 |
|
|
|
|
|
Direct
operating – non-cash stock-based compensation |
|
524 |
|
|
|
588 |
|
|
|
|
|
Exploration expenses – non-cash stock-based compensation |
|
507 |
|
|
|
690 |
|
|
|
|
|
General
& administrative – non-cash stock-based compensation |
|
10,918 |
|
|
|
11,113 |
|
|
|
|
|
Deferred
compensation plan – non-cash adjustment |
|
(13,169 |
) |
|
|
16,056 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before
income taxes, as adjusted |
|
98,446 |
|
|
|
(27,831 |
) |
|
|
454 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense
(benefit), as adjusted |
|
|
|
|
|
|
|
|
|
|
|
Current |
|
— |
|
|
|
— |
|
|
|
|
|
Deferred
(a) |
|
37,628 |
|
|
|
(10,697 |
) |
|
|
|
|
Net income (loss)
excluding certain items, a non-GAAP measure |
$ |
60,818 |
|
|
$ |
(17,134 |
) |
|
|
455 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
Non-GAAP income (loss)
income per common share |
|
|
|
|
|
|
|
|
|
|
|
Basic |
$ |
0.25 |
|
|
$ |
(0.10 |
) |
|
|
350 |
% |
Diluted |
$ |
0.25 |
|
|
$ |
(0.10 |
) |
|
|
350 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
Non-GAAP diluted shares
outstanding, if dilutive |
|
244,803 |
|
|
|
166,803 |
|
|
|
|
|
(a) Deferred taxes for 2017 are estimated to be
approximately 38%.
|
|
|
|
RANGE RESOURCES CORPORATION |
|
|
|
|
HEDGING POSITION AS OF APRIL 17, 2017 |
|
(Unaudited) – |
|
|
|
|
|
|
|
|
|
Daily Volume |
|
|
|
Hedge Price |
|
|
Gas
1 |
|
|
|
|
|
|
|
|
|
|
2Q 2017 Swaps |
|
|
|
818,764 Mmbtu |
|
|
|
$3.16 |
|
|
3Q 2017 Swaps |
|
|
|
841,196 Mmbtu |
|
|
|
$3.19 |
|
|
4Q 2017 Swaps |
|
|
|
861,196 Mmbtu |
|
|
|
$3.19 |
|
|
1Q 2018 Swaps |
|
|
|
1,020,000 Mmbtu |
|
|
|
$3.43 |
|
|
2Q-4Q 2018 Swaps |
|
|
|
220,000 Mmbtu |
|
|
|
$2.97 |
|
|
|
|
|
|
|
|
|
|
|
|
|
2Q 2017 Collars |
|
|
|
126,264 Mmbtu |
|
|
|
$3.47 x $4.14 |
|
|
3Q 2017 Collars |
|
|
|
122,609 Mmbtu |
|
|
|
$3.45 x $4.11 |
|
|
4Q 2017 Collars |
|
|
|
122,609 Mmbtu |
|
|
|
$3.45 x $4.11 |
|
|
1Q 2018 Collars |
|
|
|
60,000
Mmbtu |
|
|
|
$3.40 x $3.76 |
|
|
|
|
|
|
|
|
|
|
|
|
|
2Q 2017 Puts |
|
|
|
164,835 Mmbtu |
|
|
|
$3.47 ($0.31) 2 |
|
|
3Q 2017 Puts |
|
|
|
185,870 Mmbtu |
|
|
|
$3.50 ($0.32) 2 |
|
|
4Q 2017
Puts |
|
|
|
185,870 Mmbtu |
|
|
|
$3.50 ($0.32) 2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
|
|
|
|
|
|
|
|
2Q 2017 Swaps |
|
|
|
8,824
bbls |
|
|
|
$55.23 |
|
|
3Q 2017 Swaps |
|
|
|
8,761
bbls |
|
|
|
$56.38 |
|
|
4Q 2017 Swaps |
|
|
|
8,761
bbls |
|
|
|
$56.38 |
|
|
2018 Swaps |
|
|
|
4,000
bbls |
|
|
|
$53.74 |
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
Swaps |
|
|
|
500 bbls |
|
|
|
$51.75 |
|
|
|
|
|
|
|
|
|
|
|
|
|
C2
Ethane |
|
|
|
|
|
|
|
|
|
|
2Q 2017 Swaps |
|
|
|
3,000
bbls |
|
|
|
$0.27/gallon |
|
|
3Q 2017 Swaps |
|
|
|
3,000
bbls |
|
|
|
$0.27/gallon |
|
|
4Q 2017 Swaps |
|
|
|
3,000
bbls |
|
|
|
$0.27/gallon |
|
|
1H 2018 Swaps |
|
|
|
250
bbls |
|
|
|
$0.29/gallon |
|
|
|
|
|
|
|
|
|
|
|
|
|
C3
Propane |
|
|
|
|
|
|
|
|
|
|
2Q 2017 Swaps |
|
|
|
14,036
bbls |
|
|
|
$0.56/gallon |
|
|
3Q 2017 Swaps |
|
|
|
13,826
bbls |
|
|
|
$0.56/gallon |
|
|
4Q 2017 Swaps |
|
|
|
13,826
bbls |
|
|
|
$0.56/gallon |
|
|
2018 Swaps |
|
|
|
7,199
bbls |
|
|
|
$0.61/gallon |
|
|
|
|
|
|
|
|
|
|
|
|
|
C4 Normal
Butane |
|
|
|
|
|
|
|
|
|
|
2Q 2017 Swaps |
|
|
|
7,750
bbls |
|
|
|
$0.74/gallon |
|
|
3Q 2017 Swaps |
|
|
|
7,750
bbls |
|
|
|
$0.74/gallon |
|
|
4Q 2017 Swaps |
|
|
|
7,750
bbls |
|
|
|
$0.74/gallon |
|
|
2018 Swaps |
|
|
|
4,250
bbls |
|
|
|
$0.81/gallon |
|
|
|
|
|
|
|
|
|
|
|
|
|
C5 Natural
Gasoline |
|
|
|
|
|
|
|
|
|
|
2Q 2017 Swaps |
|
|
|
5,418
bbls |
|
|
|
$1.07/gallon |
|
|
3Q 2017 Swaps |
|
|
|
5,500
bbls |
|
|
|
$1.07/gallon |
|
|
4Q 2017 Swaps |
|
|
|
5,500
bbls |
|
|
|
$1.07/gallon |
|
|
2018 Swaps |
|
|
|
1,500
bbls |
|
|
|
$1.19/gallon |
|
(1) Range has deferred calls at a strike of $3.75 for 2H17.
Total volume of 3,300,000 Mmbtu with a deferred premium price of
$0.31 paid to Range
(2) Notes deferred premium on puts
NOTE: SEE WEBSITE FOR OTHER
SUPPLEMENTAL INFORMATION FOR THE PERIODS
Investor Contacts:
Laith Sando, Vice President – Investor Relations
817-869-4267
lsando@rangeresources.com
David Amend, Investor Relations Manager
817-869-4266
damend@rangeresources.com
Michael Freeman, Senior Financial Analyst
817-869-4264
mfreeman@rangeresources.com
Josh Stevens, Financial Analyst
817-869-1564
jrstevens@rangeresources.com
Media Contact:
Michael Mackin, Director of Public Affairs
724-873-3224
mmackin@rangeresources.com
www.rangeresources.com
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