RANGE RESOURCES CORPORATION (NYSE: RRC) today
announced its fourth quarter 2020 financial results, proved
reserves and plans for 2021.
Highlights –
- All-in 2020 capital spending was
$411 million, approximately $109 million less than original
budget
- Fourth quarter cash unit costs
improved by $0.07 per mcfe compared to prior year period
- Company record for lease operating
expense of $0.08 per mcfe during the quarter
- Reduced debt in 2020 by $86 million
compared to year-end 2019
- All-in 2021 capital budget of $425
million maintains production at ~2.15 Bcfe per day
- 2021 well costs expected to average
$570 per lateral foot, or less, lowest in Appalachia
- PV-10 of year-end proved reserves
of $8.6 billion, or $22 per share net of debt, assuming NYMEX
prices of $2.75 per Mmbtu of natural gas and $50 per barrel of
oil
- In January 2021, issued $600
million in 2029 notes extending the Company’s debt maturities
and enhancing liquidity to $2.0 billion
- Updated executive compensation
framework to enhance alignment with shareholders and support the
Company’s focus on financial strength, environmental leadership,
cost improvements, safety and generating sustainable returns for
shareholders
Commenting on the results and 2021 plans, Jeff
Ventura, the Company’s CEO said, “During 2020, Range reduced debt
while purchasing over eight million shares, refinanced near-term
maturities, lowered well costs, improved our cost structure and
delivered our operational plan safely and for less than
budgeted. These results reflect the organization’s continuing
focus on capital discipline and further strengthening our financial
position as we develop the most prolific natural gas and NGL play
in North America. Our resilience is further demonstrated by
the underlying efficiency of our 2021 capital program that can
maintain production at 2.15 Bcfe per day for only $425 million of
all-in capital. Further, our corporate sustainability report
displays our industry-leading environmental and safety efforts and
aggressive emissions targets. Looking forward, I believe Range’s
high-quality asset base, capital discipline, operational
efficiencies and leading environmental efforts provide a
sustainable business generating competitive free cash flow and
returns for shareholders.”
2021 Capital Program
Range’s 2021 all-in capital budget is $425
million. The capital budget includes approximately $400 million for
drilling and recompletions, and $25 million for leasehold and other
investments. The Company expects to turn to sales 59
Marcellus wells in 2021 with an expected average lateral length of
approximately 12,000 feet. Approximately 65% of lateral feet turned
to sales in 2021 is expected to be in Range’s liquids rich acreage.
Range also anticipates keeping in-progress well inventory
approximately unchanged going into 2022, allowing for a repeatable
and capital efficient program each year.
The table below summarizes expected 2021
activity and 2020 regarding the number of wells to sales in each
area.
|
Planned Wells |
|
Wells TIL in |
|
TIL in 2021 |
|
2020 |
SW PA Super-Rich |
17 |
|
3 |
SW PA Wet |
18 |
|
31 |
SW PA Dry |
24 |
|
33 |
Total Appalachia |
59 |
|
67 |
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.
Capital Expenditures
Fourth quarter 2020 drilling and completions
expenditures were $93 million and $15 million was invested in
acreage and gathering facilities. Total 2020 capital expenditures
were $411 million, including $377 million on drilling and
completion, and a combined $34 million on acreage, gas gathering
systems and other.
Financial Position
Range reduced outstanding debt by $86 million
during 2020, marking the third consecutive year of debt reduction
which totals $1.0 billion since the end of 2017. As
of December 31, 2020, Range had total debt outstanding
of $3.1 billion, consisting of $702 million in bank
debt, $2.4 billion in senior notes and $37
million in senior subordinated notes.
During the year, Range repurchased in the open
market and retired approximately $161 million in
principal amount of its senior and subordinated notes at a weighted
average discount to par of 25%. Range also repurchased 8.2
million shares of the Company’s common stock during the year at an
average price of $2.80 per share.
In January 2021, Range issued $600.0 million
aggregate principal amount of 8.25% senior notes due 2029 and used
net proceeds to repay borrowings under its bank credit facility.
Proforma the offering, the Company has approximately $2.0 billion
of borrowing capacity available under the commitment amount. Range
has less than $0.3 billion in notes that mature through 2022, which
are expected to be redeemed via free cash flow at strip
pricing.
Fourth Quarter 2020 Results
GAAP revenues for fourth quarter 2020
totaled $599 million, GAAP net cash provided from operating
activities (including changes in working capital) was $90
million, and GAAP net income was $38 million ($0.15 per
diluted share). Fourth quarter earnings results include
a $86 million mark-to-market derivative gain due to
decreases in commodity prices.
Non-GAAP revenues for fourth quarter 2020
totaled $531 million, and cash flow from operations before
changes in working capital, a non-GAAP measure, was $108
million. Adjusted net income comparable to analysts’
estimates, a non-GAAP measure, was $4 million ($0.02 per
diluted share) in fourth quarter 2020.
The following table details Range’s fourth
quarter 2020 unit costs per mcfe(a):
|
|
|
4Q 2020 |
|
4Q 2019 |
|
Increase |
Expenses |
|
(per mcfe) |
|
(per mcfe) |
|
(Decrease) |
|
|
|
|
|
|
|
|
Direct
operating |
|
$ |
0.08 |
|
|
$ |
0.15 |
|
|
(47%) |
Transportation,
gathering, |
|
|
|
|
|
|
|
|
|
|
processing and compression |
|
|
1.34 |
|
|
|
1.39 |
|
|
(4%) |
Production and ad
valorem taxes |
|
|
0.02 |
|
|
|
0.04 |
|
|
(50%) |
General and
administrative(a) |
|
|
0.16 |
|
|
|
0.14 |
|
|
14% |
Interest
expense(a) |
|
|
0.24 |
|
|
|
0.19 |
|
|
26% |
Total cash unit costs(b) |
|
|
1.84 |
|
|
|
1.92 |
|
|
(4%) |
Depletion,
depreciation and |
|
|
|
|
|
|
|
|
|
|
amortization (DD&A) |
|
|
0.47 |
|
|
|
0.61 |
|
|
(23%) |
Total unit costs plus DD&A(b) |
|
$ |
2.32 |
|
|
$ |
2.53 |
|
|
(8%) |
(a) |
Excludes stock-based compensation, legal settlements and
amortization of deferred financing costs. |
(b) |
May not add due to rounding. |
|
|
The following table details Range’s average
production and realized pricing for fourth quarter 2020:
|
4Q20 Production & Realized Pricing |
|
|
|
|
|
|
|
Natural Gas |
|
Natural Gas |
|
Oil |
|
NGLs |
|
Equivalent |
|
(Mcf) |
|
(Bbl) |
|
(Bbl) |
|
(Mcfe) |
|
|
|
|
|
|
|
|
Net Production per day |
|
1,464,834 |
|
|
|
6,356 |
|
|
|
97,453 |
|
|
|
2,087,690 |
|
|
|
|
|
|
|
|
|
Average NYMEX price |
$ |
2.67 |
|
|
$ |
42.70 |
|
|
|
|
|
Differential, including basis
hedging |
|
(0.57 |
) |
|
|
(10.91 |
) |
|
|
|
|
Realized prices before NYMEX
hedges |
|
2.10 |
|
|
|
31.79 |
|
|
$ |
18.02 |
|
|
$ |
2.41 |
|
Settled NYMEX hedges |
|
(0.03 |
) |
|
|
14.33 |
|
|
|
(0.53 |
) |
|
|
0.00 |
|
Average realized prices after
hedges |
$ |
2.07 |
|
|
$ |
46.12 |
|
|
$ |
17.49 |
|
|
$ |
2.41 |
|
Range’s fourth quarter production was
approximately 2.1 Bcfe net per day, including the impact of
curtailed production during fourth quarter in response to low
prices and infrastructure maintenance. The deferred production has
benefited from improving prices across all products into
mid-December and early 2021. By area, southwest Marcellus
production averaged 2.0 Bcfe per day while the northeast Marcellus
assets averaged 83 net Mmcf per day during the quarter.
Fourth quarter 2020 natural gas, NGLs and oil
price realizations (including the impact of cash-settled hedges and
derivative settlements which correspond to analysts’ estimates)
averaged $2.41 per mcfe.
- The average natural gas price,
including the impact of basis hedging, was $2.10 per mcf, or a
($0.57) per mcf differential to NYMEX. The fourth quarter natural
gas differential was impacted by storage levels in multiple regions
as well as a late start to winter weather. Starting in December and
into 2021, basis in each region has normalized, improving the
Company’s first quarter 2021 natural gas differential to NYMEX
within an expected range of ($0.20) to ($0.25) per mcf.
- Pre-hedge NGL realizations were
$18.02 per barrel, an improvement of $1.75 per barrel versus the
previous quarter driven by an improving market for propane and
heavier products. NGL prices have improved further in early 2021,
as the Mont Belvieu weighted equivalent is currently trading above
$25 per barrel in the first quarter. In addition, Range continues
to see strong NGL export premiums at Marcus Hook and expects to
maintain an average 2021 pre-hedge premium differential of between
$0.00 - $2.00 per barrel to Mont Belvieu equivalent, as a result of
access to international markets and a diversified portfolio of
sales agreements.
- Crude oil and condensate price
realizations, before realized hedges, averaged $31.79 per barrel,
or $10.91 below WTI (West Texas Intermediate). Range expects an
improving condensate differential to WTI during 2021, between $7-$9
below NYMEX, as regional production continues to decline and demand
for transportation fuels is expected to recover.
Transportation and
Gathering
Since the end of 2018, Range has reduced
transportation and gathering expenses per unit of production by
$0.17 per mcfe, from $1.51 to $1.34 in the fourth quarter of 2020.
The two-year improvement has been driven by full utilization of
both gathering and firm transport infrastructure. In 2021, Range
will have an additional 5,000 barrels per day of Mariner East
capacity, which is expected to be fully utilized with existing
production. Range continues to expect near-term and long-term
benefits of NGL exports out of the Northeast as international
demand for NGL products continues to grow. NGL export out of Marcus
Hook provides a unique supply option for that demand. In 2021,
Range expects to export over 80% of its propane and butane, the
highest percentage of propane and butane exported by any U.S.
independent, leading to strong year-over-year improvements in NGL
pricing and margins. Higher realized NGL prices for Range in 2021
will lead to a slight increase in processing costs as Range’s
processing costs are based on the price received, providing a
natural hedge against NGL price changes as the expense follows the
direction of NGL prices.
Beyond 2021, Range anticipates transportation
and gathering expenses to decline in absolute terms assuming
continued maintenance of existing production levels. By 2025 Range
expects annual gathering expense relative to 2021 to decline by
approximately $70 million, and more than $100 million per year by
2030. Importantly, the cost improvements are a result of existing
gathering arrangements and do not reflect targeted amounts.
Further improvements are also expected beyond 2030 in a production
maintenance scenario. Range also has multiple firm transportation
agreements with renewal elections during this timeframe and Range
will have the option of letting capacity expire depending on market
conditions. Transportation renewals relative to 2021 represent an
additional $175 million in potential cost improvements by 2030.
2020 Proved Reserves
Year-end 2020 proved reserves were 17.2 Tcfe,
essentially unchanged year-over-year after adjusting for asset
sales and price revisions. By volume, proved reserves were 65%
natural gas, 33% natural gas liquids and 2% crude oil and
condensate. Proved developed reserves represent 57% of the
Company’s reserves.
Summary of Changes in Proved
Reserves(in Bcfe)
Balance at December 31, 2019 |
18,192 |
|
|
|
Extensions, discoveries and additions |
1,264 |
|
Performance revisions |
420 |
|
|
|
Reclassification of PUD to unproved under SEC 5-year rule |
(961 |
) |
Price revisions |
(68 |
) |
Sales of proved reserves |
(828 |
) |
Production |
(816 |
) |
|
|
Balance at December 31,
2020 |
17,203 |
|
During 2020, Range added 1.3 Tcfe of proved
reserves through the drill-bit, driven by the Marcellus shale
development. Field level performance increased reserves by 312 Bcfe
due to continued improvement in the well performance of existing
Marcellus producing wells and 109 Bcfe of reserves associated with
proved undeveloped locations which have re-entered the Company’s
five-year drilling program. Range removed 961 Bcfe of proved
undeveloped reserves that now fall outside the SEC mandated
five-year development window, but the Company expects these proved
undeveloped reserves to be added back in future years. The Company
sold approximately 828 Bcfe of reserves during the year, associated
with the North Louisiana asset. As shown in the table below the
present value (PV10) of reserves under SEC methodology was $3.1
billion at December 31, 2020. The valuation was impacted by lower
first-of-month pricing required under SEC methodology. For
comparison, the PV10 using NYMEX reference prices of $2.75 per
Mmbtu for natural gas and $50 per barrel of oil would have been
$8.6 billion, assuming the same proven reserve volumes.
|
|
2020 SEC |
Flat Price |
|
|
Pricing(a) |
Example(b) |
|
|
|
|
Natural Gas Price ($/Mmbtu) |
$1.98 |
$2.75 |
WTI Oil Price ($/Bbl) |
$39.77 |
$50.00 |
NGL Price ($/Bbl) |
$16.14 |
$20.55 |
|
|
|
|
Proved Reserves PV10 ($ billions) |
$3.0 |
$8.6 |
(a) |
SEC benchmark prices adjusted for energy content, quality and basis
differentials were $1.68 per mcf and $30.13 per barrel of crude
oil |
(b) |
Example NYMEX prices adjusted for energy content, quality and basis
differentials were $2.53 per mcf and $43.00 per barrel of crude
oil |
|
|
Year-end 2020 reserves included 7.4 Tcfe of
proved undeveloped reserves from 361 wells planned to be developed
within the next five years with an expected development cost of
$0.32 per Mcfe. Beyond the five-year reserve calculation window,
Range has approximately 2,700 additional Marcellus locations
available for development in Southwest Pennsylvania. Range also has
a network of over 200 existing well pads designed to accommodate an
average of 20 wells per pad from any combination of Marcellus,
Utica or Upper Devonian horizons. On average, existing pads
currently contain six producing wells, providing Range the
opportunity to develop thousands of future wells while utilizing
existing roads, pads and infrastructure. In 2021, over 60% of
the wells planned to turn to sales are from pad sites with existing
production, similar to recent years.
The table below reflects Range’s estimate of the
remaining core drilling inventory for the Marcellus.
Estimated Future Marcellus Drilling
Locations - December 31, 2020(Excludes Utica and Upper
Devonian locations)
|
|
Assumed |
Producing |
Undrilled |
Area |
Net Acres |
Lateral Length |
Locations(1) |
Locations(2) |
SW Marcellus - Liquids areas |
~350,000 |
10,000 ft. |
480 |
2,600 |
SW Marcellus – Dry area |
~110,000 |
10,000 ft. |
220 |
500 |
Total |
~460,000 |
|
700 |
~3,100 |
(1) Producing locations adjusted to
10,000 foot equivalent(2) Includes anticipated
down-spacing activity
Guidance – 2021
Capital & Production Guidance
Range’s 2021 all-in capital budget is $425
million. Production for full-year 2021 is expected to average
approximately 2.15 Bcfe per day, with ~30% attributed to liquids
production.
Full Year 2021 Expense Guidance
Direct operating expense: |
$0.09 - $0.11 per mcfe |
Transportation, gathering,
processing and compression expense: |
$1.35 - $1.40 per mcfe |
Production tax expense: |
$0.02 - $0.04 per mcfe |
Exploration expense: |
$24.0 - $30.0 million |
G&A expense: |
$0.15 - $0.16 per mcfe |
Interest expense: |
$0.26 - $0.28 per mcfe |
DD&A expense: |
$0.47 - $0.50 per mcfe |
Net brokered gas marketing
expense: |
$10.0 - $16.0 million |
Full Year 2021 Price Guidance
Based on current market indications, Range expects to average
the following price differentials for its production in 2021.
Natural Gas:(1) |
NYMEX minus $0.30 to $0.40 |
Natural Gas Liquids (including
ethane):(2) |
Mont Belvieu plus $0.00 to $2.00 per barrel |
Oil/Condensate: |
WTI minus $7.00 to $9.00 |
(1) Including basis hedging(2) Weighting based on
53% ethane, 27% propane, 7% normal butane, 4% iso-butane and 9%
natural gasoline.
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. As of
January 31st, Range had approximately 70% of its expected 2021
natural gas production hedged at an average ceiling price of $2.79
per Mmbtu and an average floor price of $2.60 per Mmbtu. Similarly,
Range hedged approximately 50% of projected 2021 crude oil
production at an average floor price of $46.84 per barrel and
approximately 20% of its expected 2021 NGL revenue. Please see the
detailed hedging schedule posted on the Range website under
Investor Relations - Financial Information.
Range has also hedged Marcellus and other basis
differentials for natural gas and NGL exports to limit volatility
between benchmarks and regional prices. The combined fair value of
the natural gas basis, NGL freight and spread hedges as of December
31, 2020 was a net gain of $5.6 million.
Conference Call Information
A conference call to review the financial results is scheduled
on Wednesday, February 24 at 9:00 a.m. ET. To participate in the
call, please dial (877) 928-8777 and provide conference code
1058978 about 10 minutes prior to the scheduled start time.
A simultaneous webcast of the call may be accessed at
www.rangeresources.com. The webcast will be archived for replay on
the Company's website until March 24.
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 were historically 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.
Finding and development cost per unit is a
non-GAAP metric used in the exploration and production industry by
companies, investors and analysts. 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. This reserves metric
may not be comparable to similarly titled measurements used by
other companies. The U.S. Securities and Exchange Commission (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.
We believe that the presentation of PV10 is
relevant and useful to our investors as supplemental disclosure to
the standardized measure, or after-tax amount, because it presents
the discounted future net cash flows attributable to our proved
reserves before taking into account future corporate income taxes
and our current tax structure. While the standardized measure is
dependent on the unique tax situation of each company, PV10 is
based on prices and discount factors that are consistent for all
companies. Because of this, PV10 can be used within the industry
and by creditors and security analysts to evaluate estimated net
cash flows from proved reserves on a more comparable basis.
RANGE RESOURCES CORPORATION (NYSE:
RRC) is a leading U.S. independent natural gas
and NGL producer with operations focused on stacked-pay projects in
the Appalachian Basin. The Company is headquartered
in Fort Worth, Texas. More information about Range can
be found at www.rangeresources.com.
Included within this release are certain
“forward-looking statements” within the meaning of the federal
securities laws, including the safe harbor provisions of the
Private Securities Litigation Reform Act of 1995, that are not
limited to historical facts, but reflect Range’s current beliefs,
expectations or intentions regarding future events. Words
such as “may,” “will,” “could,” “should,” “expect,” “plan,”
“project,” “intend,” “anticipate,” “believe,” “outlook”,
“estimate,” “predict,” “potential,” “pursue,” “target,” “continue,”
and similar expressions are intended to identify such
forward-looking statements.
All statements, except for statements of
historical fact, made within regarding activities, events or
developments the Company expects, believes or anticipates will or
may occur in the future, such as those regarding future well costs,
expected asset sales, well productivity, future liquidity and
financial resilience, anticipated exports and related financial
impact, NGL market supply and demand, improving commodity
fundamentals and pricing, future capital efficiencies, future
shareholder value, emerging plays, capital spending, anticipated
drilling and completion activity, acreage prospectivity, expected
pipeline utilization and future guidance information, are
forward-looking statements within the meaning of Section 27A of the
Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. These statements are
based on assumptions and estimates that management believes are
reasonable based on currently available information; however,
management's assumptions and Range's future performance are subject
to a wide range of business risks and uncertainties and there is no
assurance that these goals and projections can or will be met. Any
number of factors could cause actual results to differ materially
from those in the forward-looking statements. Further information
on risks and uncertainties is available in Range's filings with the
Securities and Exchange Commission (SEC), including its most recent
Annual Report on Form 10-K. Unless required by law, Range
undertakes no obligation to publicly update or revise any
forward-looking statements to reflect circumstances or events after
the date they are made.
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 its 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.
Range Investor Contacts:
Laith Sando, Vice President – Investor
Relations817-869-4267lsando@rangeresources.com
Range Media Contacts:
Mark Windle, Director of Corporate Communications724-873-3223
mwindle@rangeresources.com
RANGE RESOURCES CORPORATION
STATEMENTS OF OPERATIONS |
|
|
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|
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|
|
|
|
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|
Based on GAAP reported
earnings with additional |
|
|
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|
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details of items included in
each line in Form 10-K |
|
|
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|
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(Unaudited, in thousands,
except per share data) |
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
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|
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|
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|
Three Months Ended December 31, |
|
Twelve Months Ended December 31, |
|
2020 |
|
2019 |
|
% |
|
2020 |
|
2019 |
|
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Revenues and other
income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, NGLs and oil sales (a) |
$ |
444,806 |
|
|
$ |
545,438 |
|
|
|
|
|
|
$ |
1,607,713 |
|
|
$ |
2,255,425 |
|
|
|
|
|
Derivative fair value income |
|
85,529 |
|
|
|
18,491 |
|
|
|
|
|
|
|
187,711 |
|
|
|
226,681 |
|
|
|
|
|
Brokered natural gas, marketing and other (b) |
|
67,771 |
|
|
|
41,524 |
|
|
|
|
|
|
|
171,622 |
|
|
|
344,372 |
|
|
|
|
|
ARO settlement loss (b) |
|
(4 |
) |
|
|
(2 |
) |
|
|
|
|
|
|
(22 |
) |
|
|
(13 |
) |
|
|
|
|
Other (b) |
|
784 |
|
|
|
153 |
|
|
|
|
|
|
|
1,673 |
|
|
|
1,150 |
|
|
|
|
|
Total revenues and other income |
|
598,886 |
|
|
|
605,604 |
|
|
|
-1 |
% |
|
|
1,968,697 |
|
|
|
2,827,615 |
|
|
|
-30 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
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Costs and expenses: |
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating |
|
15,945 |
|
|
|
33,323 |
|
|
|
|
|
|
|
91,079 |
|
|
|
134,348 |
|
|
|
|
|
Direct operating – non-cash stock-based compensation (c) |
|
268 |
|
|
|
469 |
|
|
|
|
|
|
|
1,078 |
|
|
|
1,928 |
|
|
|
|
|
Transportation, gathering, processing and compression |
|
256,742 |
|
|
|
299,511 |
|
|
|
|
|
|
|
1,088,490 |
|
|
|
1,199,297 |
|
|
|
|
|
Production and ad valorem taxes |
|
3,935 |
|
|
|
8,963 |
|
|
|
|
|
|
|
24,617 |
|
|
|
37,967 |
|
|
|
|
|
Brokered natural gas and marketing |
|
69,053 |
|
|
|
46,199 |
|
|
|
|
|
|
|
186,900 |
|
|
|
358,036 |
|
|
|
|
|
Brokered natural gas and marketing – non-cash |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
stock-based compensation (c) |
|
511 |
|
|
|
333 |
|
|
|
|
|
|
|
1,416 |
|
|
|
1,856 |
|
|
|
|
|
Exploration |
|
9,076 |
|
|
|
9,156 |
|
|
|
|
|
|
|
31,375 |
|
|
|
35,117 |
|
|
|
|
|
Exploration – non-cash stock-based compensation (c) |
|
388 |
|
|
|
194 |
|
|
|
|
|
|
|
1,279 |
|
|
|
1,566 |
|
|
|
|
|
Abandonment and impairment of unproved properties |
|
2,730 |
|
|
|
1,193,711 |
|
|
|
|
|
|
|
19,334 |
|
|
|
1,235,342 |
|
|
|
|
|
General and administrative |
|
31,307 |
|
|
|
30,269 |
|
|
|
|
|
|
|
123,859 |
|
|
|
137,694 |
|
|
|
|
|
General and administrative – non-cash stock-based |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
compensation (c) |
|
8,834 |
|
|
|
7,500 |
|
|
|
|
|
|
|
32,905 |
|
|
|
35,061 |
|
|
|
|
|
General and administrative – lawsuit settlements |
|
579 |
|
|
|
542 |
|
|
|
|
|
|
|
2,251 |
|
|
|
2,577 |
|
|
|
|
|
General and administrative – rig release penalty |
|
— |
|
|
|
— |
|
|
|
|
|
|
|
— |
|
|
|
1,436 |
|
|
|
|
|
General and administrative – bad debt expense |
|
— |
|
|
|
4,482 |
|
|
|
|
|
|
|
400 |
|
|
|
4,341 |
|
|
|
|
|
Exit and termination costs |
|
13,739 |
|
|
|
4,535 |
|
|
|
|
|
|
|
545,244 |
|
|
|
7,535 |
|
|
|
|
|
Exit and termination costs – non-cash stock-based |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
compensation (c) |
|
145 |
|
|
|
1,946 |
|
|
|
|
|
|
|
2,165 |
|
|
|
1,971 |
|
|
|
|
|
Deferred compensation plan (d) |
|
2,254 |
|
|
|
960 |
|
|
|
|
|
|
|
12,541 |
|
|
|
(15,472 |
) |
|
|
|
|
Interest expense |
|
46,389 |
|
|
|
42,043 |
|
|
|
|
|
|
|
184,201 |
|
|
|
186,916 |
|
|
|
|
|
Interest expense – amortization of deferred financing costs
(e) |
|
2,137 |
|
|
|
1,981 |
|
|
|
|
|
|
|
8,466 |
|
|
|
7,369 |
|
|
|
|
|
Gain on early extinguishment of debt |
|
25 |
|
|
|
(2,430 |
) |
|
|
|
|
|
|
(14,068 |
) |
|
|
(5,415 |
) |
|
|
|
|
Depletion, depreciation and amortization |
|
90,551 |
|
|
|
130,869 |
|
|
|
|
|
|
|
394,330 |
|
|
|
548,843 |
|
|
|
|
|
Impairment of proved property and other assets |
|
— |
|
|
|
1,095,634 |
|
|
|
|
|
|
|
78,955 |
|
|
|
1,095,634 |
|
|
|
|
|
Loss (gain) on sale of assets |
|
1,652 |
|
|
|
(407 |
) |
|
|
|
|
|
|
(110,791 |
) |
|
|
30,256 |
|
|
|
|
|
Total costs and expenses |
|
556,260 |
|
|
|
2,909,783 |
|
|
|
-81 |
% |
|
|
2,706,026 |
|
|
|
5,044,203 |
|
|
|
-46 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income
taxes |
|
42,626 |
|
|
|
(2,304,179 |
) |
|
|
102 |
% |
|
|
(737,329 |
) |
|
|
(2,216,588 |
) |
|
|
67 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax (benefit)
expense: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
(157 |
) |
|
|
2,068 |
|
|
|
|
|
|
|
(523 |
) |
|
|
6,147 |
|
|
|
|
|
Deferred |
|
4,382 |
|
|
|
(500,927 |
) |
|
|
|
|
|
|
(25,029 |
) |
|
|
(506,438 |
) |
|
|
|
|
|
|
4,225 |
|
|
|
(498,859 |
) |
|
|
|
|
|
|
(25,552 |
) |
|
|
(500,291 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
$ |
38,401 |
|
|
$ |
(1,805,320 |
) |
|
|
102 |
% |
|
$ |
(711,777 |
) |
|
$ |
(1,716,297 |
) |
|
|
59 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) Per
Common Share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
$ |
0.16 |
|
|
$ |
(7.27 |
) |
|
|
|
|
|
$ |
(2.95 |
) |
|
$ |
(6.92 |
) |
|
|
|
|
Diluted |
$ |
0.15 |
|
|
$ |
(7.27 |
) |
|
|
|
|
|
$ |
(2.95 |
) |
|
$ |
(6.92 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares
outstanding, as reported: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
240,174 |
|
|
|
248,277 |
|
|
|
-3 |
% |
|
|
241,373 |
|
|
|
247,970 |
|
|
|
-3 |
% |
Diluted |
|
246,286 |
|
|
|
248,277 |
|
|
|
-1 |
% |
|
|
241,373 |
|
|
|
247,970 |
|
|
|
-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-K. |
|
(c) |
Costs associated with stock compensation and restricted stock
amortization, which have been reflected in the categories
associated |
|
|
with the direct personnel costs, which are combined with the cash
costs in the 10-K. |
|
(d) |
Reflects the change in market value of the vested Company stock
held in the deferred compensation plan. |
|
(e) |
Included in interest expense in the 10-K. |
|
|
|
RANGE RESOURCES CORPORATION
BALANCE SHEETS |
|
|
|
|
|
|
|
(In thousands) |
December 31, |
|
December 31, |
|
2020 |
|
2019 |
|
(Audited) |
|
(Audited) |
Assets |
|
|
|
|
|
|
|
Current assets |
$ |
266,508 |
|
|
$ |
290,954 |
|
Derivative assets |
|
40,012 |
|
|
|
137,554 |
|
Natural gas and oil properties, successful efforts method |
|
5,686,809 |
|
|
|
6,041,035 |
|
Transportation and field assets |
|
4,161 |
|
|
|
5,375 |
|
Operating lease right-of-use assets |
|
63,581 |
|
|
|
62,053 |
|
Other |
|
75,865 |
|
|
|
75,432 |
|
|
$ |
6,136,936 |
|
|
$ |
6,612,403 |
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders’
Equity |
|
|
|
|
|
|
|
Current liabilities |
$ |
673,445 |
|
|
$ |
551,032 |
|
Asset retirement obligations |
|
6,689 |
|
|
|
2,393 |
|
Derivative liabilities |
|
26,707 |
|
|
|
13,119 |
|
|
|
|
|
|
|
|
|
Bank debt |
|
693,123 |
|
|
|
464,319 |
|
Senior notes |
|
2,329,745 |
|
|
|
2,659,844 |
|
Senior subordinated notes |
|
17,384 |
|
|
|
48,774 |
|
Total debt |
|
3,040,252 |
|
|
|
3,172,937 |
|
|
|
|
|
|
|
|
|
Deferred tax liability |
|
135,267 |
|
|
|
160,196 |
|
Derivative liabilities |
|
9,746 |
|
|
|
949 |
|
Deferred compensation liability |
|
81,481 |
|
|
|
64,070 |
|
Operating lease liabilities |
|
43,155 |
|
|
|
41,068 |
|
Asset retirement obligations and other liabilities |
|
91,157 |
|
|
|
259,151 |
|
Divestiture contract obligation |
|
391,502 |
|
|
|
— |
|
|
|
|
|
|
|
|
|
Common stock and retained deficit |
|
1,668,146 |
|
|
|
2,355,512 |
|
Other comprehensive loss |
|
(479 |
) |
|
|
(788 |
) |
Common stock held in treasury stock |
|
(30,132 |
) |
|
|
(7,236 |
) |
Total stockholders’ equity |
|
1,637,535 |
|
|
|
2,347,488 |
|
|
$ |
6,136,936 |
|
|
$ |
6,612,403 |
|
RECONCILIATION OF
TOTAL REVENUES AND OTHER INCOME TO TOTAL REVENUE EXCLUDING CERTAIN
ITEMS, a non-GAAP measure |
|
|
|
(Unaudited, in thousands) |
|
|
|
|
Three Months Ended December 31, |
|
Twelve Months Ended December 31, |
|
2020 |
|
2019 |
|
% |
|
2020 |
|
2019 |
|
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues and other
income, as reported |
$ |
598,886 |
|
|
$ |
605,604 |
|
|
|
-1 |
% |
|
$ |
1,968,697 |
|
|
$ |
2,827,615 |
|
|
|
-30 |
% |
Adjustment for certain special
items: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total change in fair value related to derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
prior to settlement (gain) loss |
|
(68,143 |
) |
|
|
31,544 |
|
|
|
|
|
|
|
134,918 |
|
|
|
(38,297 |
) |
|
|
|
|
ARO settlement (gain) loss |
|
4 |
|
|
|
2 |
|
|
|
|
|
|
|
22 |
|
|
|
13 |
|
|
|
|
|
Total revenues, as adjusted,
non-GAAP |
$ |
530,747 |
|
|
$ |
637,150 |
|
|
|
-17 |
% |
|
$ |
2,103,637 |
|
|
$ |
2,789,331 |
|
|
|
-25 |
% |
RANGE RESOURCES CORPORATION
CASH FLOWS FROM OPERATING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended December 31, |
|
Twelve Months Ended December 31, |
|
2020 |
|
2019 |
|
2020 |
|
2019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
$ |
38,401 |
|
|
$ |
(1,805,320 |
) |
|
$ |
(711,777 |
) |
|
$ |
(1,716,297 |
) |
Adjustments to reconcile net
cash provided from continuing operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax benefit |
|
4,382 |
|
|
|
(500,927 |
) |
|
|
(25,029 |
) |
|
|
(506,438 |
) |
Depletion, depreciation, amortization and impairment |
|
90,551 |
|
|
|
1,226,503 |
|
|
|
473,285 |
|
|
|
1,644,477 |
|
Exploration dry hole and impairment costs |
|
888 |
|
|
|
(11 |
) |
|
|
888 |
|
|
|
(11 |
) |
Abandonment and impairment of unproved properties |
|
2,730 |
|
|
|
1,193,711 |
|
|
|
19,334 |
|
|
|
1,235,342 |
|
Derivative fair value loss (income) |
|
(85,529 |
) |
|
|
(18,491 |
) |
|
|
(187,711 |
) |
|
|
(226,681 |
) |
Cash settlements on derivative financial instruments |
|
17,386 |
|
|
|
50,035 |
|
|
|
322,629 |
|
|
|
188,384 |
|
Divestiture contract obligation |
|
13,245 |
|
|
|
— |
|
|
|
499,934 |
|
|
|
— |
|
Allowance for bad debts |
|
— |
|
|
|
4,482 |
|
|
|
400 |
|
|
|
4,341 |
|
Amortization of deferred issuance costs and other |
|
1,896 |
|
|
|
1,593 |
|
|
|
6,919 |
|
|
|
6,455 |
|
Deferred and stock-based compensation |
|
10,172 |
|
|
|
10,481 |
|
|
|
48,552 |
|
|
|
24,891 |
|
Loss (gain) on sale of assets and other |
|
1,652 |
|
|
|
(407 |
) |
|
|
(110,791 |
) |
|
|
30,256 |
|
Loss (gain) on early extinguishment of debt |
|
25 |
|
|
|
(2,430 |
) |
|
|
(14,068 |
) |
|
|
(5,415 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in working capital: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
(66,804 |
) |
|
|
(27,318 |
) |
|
|
24,539 |
|
|
|
214,196 |
|
Inventory and other |
|
6,796 |
|
|
|
8,544 |
|
|
|
1,010 |
|
|
|
4,520 |
|
Accounts payable |
|
20,134 |
|
|
|
(7,729 |
) |
|
|
(32,686 |
) |
|
|
(60,374 |
) |
Accrued liabilities and other |
|
33,781 |
|
|
|
(304 |
) |
|
|
(46,748 |
) |
|
|
(155,803 |
) |
Net changes in working capital |
|
(6,093 |
) |
|
|
(26,807 |
) |
|
|
(53,885 |
) |
|
|
2,539 |
|
Net cash provided from operating activities |
$ |
89,706 |
|
|
$ |
132,412 |
|
|
$ |
268,680 |
|
|
$ |
681,843 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RECONCILIATION OF NET
CASH PROVIDED FROM OPERATING ACTIVITIES, AS REPORTED, TO CASH FLOW
FROM OPERATIONS BEFORE CHANGES IN WORKING CAPITAL, a non-GAAP
measure |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited, in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended December 31, |
|
Twelve Months Ended December 31, |
|
2020 |
|
2019 |
|
2020 |
|
2019 |
Net cash provided from
operating activities, as reported |
$ |
89,706 |
|
|
$ |
132,412 |
|
|
$ |
268,680 |
|
|
$ |
681,843 |
|
Net changes in working capital |
|
6,093 |
|
|
|
26,807 |
|
|
|
53,885 |
|
|
|
(2,539 |
) |
Exploration expense |
|
8,188 |
|
|
|
9,167 |
|
|
|
30,487 |
|
|
|
35,128 |
|
Lawsuit settlements |
|
579 |
|
|
|
542 |
|
|
|
2,251 |
|
|
|
2,577 |
|
Exit and termination costs – severance costs only |
|
271 |
|
|
|
4,535 |
|
|
|
5,908 |
|
|
|
7,535 |
|
Accrued transportation contract release including accretion |
|
222 |
|
|
|
— |
|
|
|
10,900 |
|
|
|
— |
|
One-time midstream termination payment |
|
— |
|
|
|
— |
|
|
|
28,500 |
|
|
|
— |
|
Rig release penalty |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
1,436 |
|
Non-cash compensation adjustment |
|
2,474 |
|
|
|
1,311 |
|
|
|
4,403 |
|
|
|
2,946 |
|
Cash flow from operations
before changes in working capital – non-GAAP measure |
$ |
107,533 |
|
|
$ |
174,774 |
|
|
$ |
405,014 |
|
|
$ |
728,926 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ADJUSTED WEIGHTED
AVERAGE SHARES OUTSTANDING |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited, in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended December 31, |
|
Twelve Months Ended December 31, |
|
2020 |
|
2019 |
|
2020 |
|
2019 |
Basic: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares
outstanding |
|
246,320 |
|
|
|
251,430 |
|
|
|
247,050 |
|
|
|
251,105 |
|
Stock held by deferred
compensation plan |
|
(6,146 |
) |
|
|
(3,153 |
) |
|
|
(5,677 |
) |
|
|
(3,135 |
) |
Adjusted basic |
|
240,174 |
|
|
|
248,277 |
|
|
|
241,373 |
|
|
|
247,970 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dilutive: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares
outstanding |
|
246,320 |
|
|
|
251,430 |
|
|
|
247,050 |
|
|
|
251,105 |
|
Dilutive stock options under
treasury method |
|
(34 |
) |
|
|
(3,153 |
) |
|
|
(5,677 |
) |
|
|
(3,135 |
) |
Adjusted dilutive |
|
246,286 |
|
|
|
248,277 |
|
|
|
241,373 |
|
|
|
247,970 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 December 31, |
|
Twelve Months Ended December 31, |
|
2020 |
|
2019 |
|
% |
|
2020 |
|
2019 |
|
% |
Natural gas, NGL and oil sales components: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales |
$ |
264,646 |
|
|
$ |
325,515 |
|
|
|
|
|
|
$ |
943,740 |
|
|
$ |
1,388,838 |
|
|
|
|
|
NGL sales |
|
161,569 |
|
|
|
173,099 |
|
|
|
|
|
|
|
578,454 |
|
|
|
681,134 |
|
|
|
|
|
Oil sales |
|
18,591 |
|
|
|
46,824 |
|
|
|
|
|
|
|
85,519 |
|
|
|
185,453 |
|
|
|
|
|
Total oil and gas sales, as
reported |
$ |
444,806 |
|
|
$ |
545,438 |
|
|
|
-18 |
% |
|
$ |
1,607,713 |
|
|
$ |
2,255,425 |
|
|
|
-29 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative fair value income
(loss), as reported: |
$ |
85,529 |
|
|
$ |
18,491 |
|
|
|
|
|
|
$ |
187,711 |
|
|
$ |
226,681 |
|
|
|
|
|
Cash settlements on derivative
financial instruments – (gain) loss: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas |
|
(13,753 |
) |
|
|
(46,920 |
) |
|
|
|
|
|
|
(258,797 |
) |
|
|
(139,253 |
) |
|
|
|
|
NGLs |
|
4,745 |
|
|
|
(3,233 |
) |
|
|
|
|
|
|
(11,288 |
) |
|
|
(51,068 |
) |
|
|
|
|
Crude Oil |
|
(8,378 |
) |
|
|
118 |
|
|
|
|
|
|
|
(52,544 |
) |
|
|
1,937 |
|
|
|
|
|
Total change in fair value
related to derivatives prior to settlement, a non-GAAP measure |
$ |
68,143 |
|
|
$ |
(31,544 |
) |
|
|
|
|
|
$ |
(134,918 |
) |
|
$ |
38,297 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation, gathering,
processing and compression components: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas |
$ |
155,766 |
|
|
$ |
185,273 |
|
|
|
|
|
|
$ |
650,071 |
|
|
$ |
740,061 |
|
|
|
|
|
NGLs |
|
100,983 |
|
|
|
114,238 |
|
|
|
|
|
|
|
437,474 |
|
|
|
459,236 |
|
|
|
|
|
Oil |
|
(7 |
) |
|
|
— |
|
|
|
|
|
|
|
945 |
|
|
|
— |
|
|
|
|
|
Total transportation,
gathering, processing and compression, as reported |
$ |
256,742 |
|
|
$ |
299,511 |
|
|
|
|
|
|
$ |
1,088,490 |
|
|
$ |
1,199,297 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, NGL and oil
sales, including cash-settled derivatives: (c) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales |
$ |
278,399 |
|
|
$ |
372,435 |
|
|
|
|
|
|
$ |
1,202,537 |
|
|
$ |
1,528,091 |
|
|
|
|
|
NGL sales |
|
156,824 |
|
|
|
176,332 |
|
|
|
|
|
|
|
589,742 |
|
|
|
732,202 |
|
|
|
|
|
Oil sales |
|
26,969 |
|
|
|
46,706 |
|
|
|
|
|
|
|
138,063 |
|
|
|
183,516 |
|
|
|
|
|
Total |
$ |
462,192 |
|
|
$ |
595,473 |
|
|
|
-22 |
% |
|
$ |
1,930,342 |
|
|
$ |
2,443,809 |
|
|
|
-21 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production of oil and gas
during the periods (a): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mcf) |
|
134,764,765 |
|
|
|
150,708,420 |
|
|
|
-11 |
% |
|
|
574,529,290 |
|
|
|
578,114,351 |
|
|
|
-1 |
% |
NGL (bbl) |
|
8,965,697 |
|
|
|
9,879,081 |
|
|
|
-9 |
% |
|
|
37,491,546 |
|
|
|
38,850,130 |
|
|
|
-3 |
% |
Oil (bbl) |
|
584,754 |
|
|
|
962,390 |
|
|
|
-39 |
% |
|
|
2,829,495 |
|
|
|
3,689,805 |
|
|
|
-23 |
% |
Gas equivalent (mcfe) (b) |
|
192,067,471 |
|
|
|
215,757,246 |
|
|
|
-11 |
% |
|
|
816,455,536 |
|
|
|
833,353,961 |
|
|
|
-2 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production of oil and gas –
average per day (a): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mcf) |
|
1,464,834 |
|
|
|
1,638,135 |
|
|
|
-11 |
% |
|
|
1,569,752 |
|
|
|
1,583,875 |
|
|
|
-1 |
% |
NGL (bbl) |
|
97,453 |
|
|
|
107,381 |
|
|
|
-9 |
% |
|
|
102,436 |
|
|
|
106,439 |
|
|
|
-4 |
% |
Oil (bbl) |
|
6,356 |
|
|
|
10,461 |
|
|
|
-39 |
% |
|
|
7,731 |
|
|
|
10,109 |
|
|
|
-24 |
% |
Gas equivalent (mcfe) (b) |
|
2,087,690 |
|
|
|
2,345,187 |
|
|
|
-11 |
% |
|
|
2,230,753 |
|
|
|
2,283,162 |
|
|
|
-2 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices, excluding
derivative settlements and before third party transportation
costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mcf) |
$ |
1.96 |
|
|
$ |
2.16 |
|
|
|
-9 |
% |
|
$ |
1.64 |
|
|
$ |
2.40 |
|
|
|
-32 |
% |
NGL (bbl) |
$ |
18.02 |
|
|
$ |
17.52 |
|
|
|
3 |
% |
|
$ |
15.43 |
|
|
$ |
17.53 |
|
|
|
-12 |
% |
Oil (bbl) |
$ |
31.79 |
|
|
$ |
48.65 |
|
|
|
-35 |
% |
|
$ |
30.22 |
|
|
$ |
50.26 |
|
|
|
-40 |
% |
Gas equivalent (mcfe) (b) |
$ |
2.32 |
|
|
$ |
2.53 |
|
|
|
-8 |
% |
|
$ |
1.97 |
|
|
$ |
2.71 |
|
|
|
-27 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices, including
derivative settlements before third party transportation costs:
(c) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mcf) |
$ |
2.07 |
|
|
$ |
2.47 |
|
|
|
-16 |
% |
|
$ |
2.09 |
|
|
$ |
2.64 |
|
|
|
-21 |
% |
NGL (bbl) |
$ |
17.49 |
|
|
$ |
17.85 |
|
|
|
-2 |
% |
|
$ |
15.73 |
|
|
$ |
18.85 |
|
|
|
-17 |
% |
Oil (bbl) |
$ |
46.12 |
|
|
$ |
48.53 |
|
|
|
-5 |
% |
|
$ |
48.79 |
|
|
$ |
49.74 |
|
|
|
-2 |
% |
Gas equivalent (mcfe) (b) |
$ |
2.41 |
|
|
$ |
2.76 |
|
|
|
-13 |
% |
|
$ |
2.36 |
|
|
$ |
2.93 |
|
|
|
-19 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices, including
derivative settlements and after third party transportation costs:
(d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mcf) |
$ |
0.91 |
|
|
$ |
1.24 |
|
|
|
-27 |
% |
|
$ |
0.96 |
|
|
$ |
1.36 |
|
|
|
-29 |
% |
NGL (bbl) |
$ |
6.23 |
|
|
$ |
6.29 |
|
|
|
-1 |
% |
|
$ |
4.06 |
|
|
$ |
7.03 |
|
|
|
-42 |
% |
Oil (bbl) |
$ |
46.13 |
|
|
$ |
48.53 |
|
|
|
-5 |
% |
|
$ |
48.46 |
|
|
$ |
49.74 |
|
|
|
-3 |
% |
Gas equivalent (mcfe) (b) |
$ |
1.07 |
|
|
$ |
1.37 |
|
|
|
-22 |
% |
|
$ |
1.03 |
|
|
$ |
1.49 |
|
|
|
-31 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation, gathering and
compression expense per mcfe |
$ |
1.34 |
|
|
$ |
1.39 |
|
|
|
-4 |
% |
|
$ |
1.33 |
|
|
$ |
1.44 |
|
|
|
-7 |
% |
|
(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 TAXES
AS REPORTED TO INCOME BEFORE INCOME TAXES EXCLUDING CERTAIN
ITEMS, a non-GAAP measure |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited, in thousands,
except per share data) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended December 31, |
|
Twelve Months Ended December 31, |
|
2020 |
|
2019 |
|
% |
|
2020 |
|
2019 |
|
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
before income taxes, as reported |
$ |
42,626 |
|
|
$ |
(2,304,179 |
) |
|
|
102 |
% |
|
$ |
(737,329 |
) |
|
$ |
(2,216,588 |
) |
|
|
67 |
% |
Adjustment for certain special
items: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss (gain) on sale of assets |
|
1,652 |
|
|
|
(407 |
) |
|
|
|
|
|
|
(110,791 |
) |
|
|
30,256 |
|
|
|
|
|
Loss on ARO settlements |
|
4 |
|
|
|
2 |
|
|
|
|
|
|
|
22 |
|
|
|
13 |
|
|
|
|
|
Change in fair value related to derivatives prior to
settlement |
|
(68,143 |
) |
|
|
31,544 |
|
|
|
|
|
|
|
134,918 |
|
|
|
(38,297 |
) |
|
|
|
|
Abandonment and impairment of unproved properties |
|
2,730 |
|
|
|
1,193,711 |
|
|
|
|
|
|
|
19,334 |
|
|
|
1,235,342 |
|
|
|
|
|
Rig release penalty |
|
— |
|
|
|
— |
|
|
|
|
|
|
|
— |
|
|
|
1,436 |
|
|
|
|
|
Loss (gain) on early extinguishment of debt |
|
25 |
|
|
|
(2,430 |
) |
|
|
|
|
|
|
(14,068 |
) |
|
|
(5,415 |
) |
|
|
|
|
Impairment of proved property and other assets |
|
— |
|
|
|
1,095,634 |
|
|
|
|
|
|
|
78,955 |
|
|
|
1,095,634 |
|
|
|
|
|
Lawsuit settlements |
|
579 |
|
|
|
542 |
|
|
|
|
|
|
|
2,251 |
|
|
|
2,577 |
|
|
|
|
|
Exit and termination costs |
|
13,739 |
|
|
|
4,535 |
|
|
|
|
|
|
|
545,244 |
|
|
|
7,535 |
|
|
|
|
|
Exit and termination costs – non-cash stock-based compensation |
|
145 |
|
|
|
1,946 |
|
|
|
|
|
|
|
2,165 |
|
|
|
1,971 |
|
|
|
|
|
Brokered natural gas and marketing – non-cash
stock-basedcompensation |
|
511 |
|
|
|
333 |
|
|
|
|
|
|
|
1,416 |
|
|
|
1,856 |
|
|
|
|
|
Direct operating – non-cash stock-based compensation |
|
268 |
|
|
|
469 |
|
|
|
|
|
|
|
1,078 |
|
|
|
1,928 |
|
|
|
|
|
Exploration expenses – non-cash stock-based compensation |
|
388 |
|
|
|
194 |
|
|
|
|
|
|
|
1,279 |
|
|
|
1,566 |
|
|
|
|
|
General & administrative – non-cash stock-based
compensation |
|
8,834 |
|
|
|
7,500 |
|
|
|
|
|
|
|
32,905 |
|
|
|
35,061 |
|
|
|
|
|
Deferred compensation plan – non-cash adjustment |
|
2,254 |
|
|
|
960 |
|
|
|
|
|
|
|
12,541 |
|
|
|
(15,472 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income
taxes, as adjusted |
|
5,612 |
|
|
|
30,354 |
|
|
|
-82 |
% |
|
|
(30,080 |
) |
|
|
139,403 |
|
|
|
-122 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense (benefit),
as adjusted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
(157 |
) |
|
|
2,068 |
|
|
|
|
|
|
|
(523 |
) |
|
|
6,147 |
|
|
|
|
|
Deferred (a) |
|
1,403 |
|
|
|
7,588 |
|
|
|
|
|
|
|
(7,520 |
) |
|
|
34,867 |
|
|
|
|
|
Net income (loss) excluding
certain items, a non-GAAP measure |
$ |
4,366 |
|
|
$ |
20,698 |
|
|
|
-79 |
% |
|
$ |
(22,037 |
) |
|
$ |
98,389 |
|
|
|
-122 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-GAAP income (loss) per
common share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
$ |
0.02 |
|
|
$ |
0.08 |
|
|
|
-75 |
% |
|
$ |
(0.09 |
) |
|
$ |
0.40 |
|
|
|
-123 |
% |
Diluted |
$ |
0.02 |
|
|
$ |
0.08 |
|
|
|
-75 |
% |
|
$ |
(0.09 |
) |
|
$ |
0.40 |
|
|
|
-123 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-GAAP diluted shares
outstanding, if dilutive |
|
246,286 |
|
|
|
248,889 |
|
|
|
|
|
|
|
241,373 |
|
|
|
249,054 |
|
|
|
|
|
|
(a) |
Deferred taxes are estimated to be approximately 25% for 2020 and
2019. |
|
|
|
RANGE RESOURCES CORPORATION
RECONCILIATION OF NET INCOME (LOSS),
EXCLUDINGCERTAIN ITEMS AND ADJUSTED EARNINGS PER
SHARE, non-GAAP measures |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands, except per
share data) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months EndedDecember 31, |
|
Twelve Months EndedDecember 31, |
|
2020 |
|
2019 |
|
2020 |
|
2019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss), as
reported |
$ |
38,401 |
|
|
$ |
(1,805,320 |
) |
|
$ |
(711,777 |
) |
|
$ |
(1,716,297 |
) |
Adjustment for certain
special items: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss (gain) on sale of assets |
|
1,652 |
|
|
|
(407 |
) |
|
|
(110,791 |
) |
|
|
30,256 |
|
Loss (gain) on ARO settlements |
|
4 |
|
|
|
2 |
|
|
|
22 |
|
|
|
13 |
|
Gain on early extinguishment of debt |
|
25 |
|
|
|
(2,430 |
) |
|
|
(14,068 |
) |
|
|
(5,415 |
) |
Change in fair value related to derivatives prior to
settlement |
|
(68,143 |
) |
|
|
31,544 |
|
|
|
134,918 |
|
|
|
(38,297 |
) |
Impairment of proved property |
|
— |
|
|
|
1,095,634 |
|
|
|
78,955 |
|
|
|
1,095,634 |
|
Abandonment and impairment of unproved properties |
|
2,730 |
|
|
|
1,193,711 |
|
|
|
19,334 |
|
|
|
1,235,342 |
|
Lawsuit settlements |
|
579 |
|
|
|
542 |
|
|
|
2,251 |
|
|
|
2,577 |
|
Rig release penalty |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
1,436 |
|
Exit and termination costs |
|
13,739 |
|
|
|
4,535 |
|
|
|
545,244 |
|
|
|
7,535 |
|
Non-cash stock-based compensation |
|
10,146 |
|
|
|
10,442 |
|
|
|
38,843 |
|
|
|
42,382 |
|
Deferred compensation plan |
|
2,254 |
|
|
|
960 |
|
|
|
12,541 |
|
|
|
(15,472 |
) |
Tax impact |
|
2,979 |
|
|
|
(508,515 |
) |
|
|
(17,509 |
) |
|
|
(541,305 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
excluding certain items, a non-GAAP measure |
$ |
4,366 |
|
|
$ |
20,698 |
|
|
$ |
(22,037 |
) |
|
$ |
98,389 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per
diluted share, as reported |
$ |
0.15 |
|
|
$ |
(7.27 |
) |
|
$ |
(2.95 |
) |
|
$ |
(6.92 |
) |
Adjustment for certain
special items per diluted share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss (gain) on sale of assets |
|
0.01 |
|
|
|
(0.00 |
) |
|
|
(0.46 |
) |
|
|
0.12 |
|
Loss (gain) on ARO settlements |
|
0.00 |
|
|
|
0.00 |
|
|
|
0.00 |
|
|
|
0.00 |
|
Loss (gain) on early extinguishment of debt |
|
0.00 |
|
|
|
(0.01 |
) |
|
|
(0.06 |
) |
|
|
(0.02 |
) |
Change in fair value related to derivatives prior to
settlement |
|
(0.28 |
) |
|
|
0.13 |
|
|
|
0.56 |
|
|
|
(0.15 |
) |
Impairment of proved property and other assets |
|
— |
|
|
|
4.41 |
|
|
|
0.33 |
|
|
|
4.42 |
|
Abandonment and impairment of unproved properties |
|
0.01 |
|
|
|
4.81 |
|
|
|
0.08 |
|
|
|
4.98 |
|
Lawsuit settlements |
|
0.00 |
|
|
|
0.00 |
|
|
|
0.01 |
|
|
|
0.01 |
|
Rig release penalty |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
0.01 |
|
Exit and termination costs |
|
0.06 |
|
|
|
0.02 |
|
|
|
2.26 |
|
|
|
0.03 |
|
Non-cash stock-based compensation |
|
0.04 |
|
|
|
0.04 |
|
|
|
0.16 |
|
|
|
0.17 |
|
Deferred compensation plan |
|
0.01 |
|
|
|
0.00 |
|
|
|
0.05 |
|
|
|
(0.06 |
) |
Adjustment for rounding differences |
|
0.01 |
|
|
|
— |
|
|
|
— |
|
|
|
(0.01 |
) |
Tax impact |
|
0.01 |
|
|
|
(2.05 |
) |
|
|
(0.07 |
) |
|
|
(2.18 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per
diluted share, excluding certain items, a non- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GAAP measure |
$ |
0.02 |
|
|
$ |
0.08 |
|
|
$ |
(0.09 |
) |
|
$ |
0.40 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted earnings per
share, a non-GAAP measure: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
$ |
0.02 |
|
|
$ |
0.08 |
|
|
$ |
(0.09 |
) |
|
$ |
0.40 |
|
Diluted |
$ |
0.02 |
|
|
$ |
0.08 |
|
|
$ |
(0.09 |
) |
|
$ |
0.40 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RANGE RESOURCES CORPORATION
RECONCILIATION OF CASH MARGIN PER MCFE, a
non-GAAP measure |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited, in thousands,
except per unit data) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months EndedDecember 31, |
|
Twelve Months EndedDecember 31, |
|
2020 |
|
2019 |
|
2020 |
|
2019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, NGL and oil sales, as reported |
$ |
444,806 |
|
|
$ |
545,438 |
|
|
$ |
1,607,713 |
|
|
$ |
2,255,425 |
|
Derivative fair value income, as reported |
|
85,529 |
|
|
|
18,491 |
|
|
|
187,711 |
|
|
|
226,681 |
|
Less non-cash fair value (gain) loss |
|
(68,143 |
) |
|
|
31,544 |
|
|
|
134,918 |
|
|
|
(38,297 |
) |
Brokered natural gas and marketing and other, as reported |
|
68,551 |
|
|
|
41,675 |
|
|
|
173,273 |
|
|
|
345,509 |
|
Less ARO settlement and other (gains) losses |
|
(780 |
) |
|
|
(151 |
) |
|
|
(1,651 |
) |
|
|
(1,137 |
) |
Cash revenue applicable to production |
|
529,963 |
|
|
|
636,997 |
|
|
|
2,101,964 |
|
|
|
2,788,181 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating, as reported |
|
16,213 |
|
|
|
33,792 |
|
|
|
92,157 |
|
|
|
136,276 |
|
Less direct operating stock-based compensation |
|
(268 |
) |
|
|
(469 |
) |
|
|
(1,078 |
) |
|
|
(1,928 |
) |
Transportation, gathering and compression, as reported |
|
256,742 |
|
|
|
299,511 |
|
|
|
1,088,490 |
|
|
|
1,199,297 |
|
Production and ad valorem taxes, as reported |
|
3,935 |
|
|
|
8,963 |
|
|
|
24,617 |
|
|
|
37,967 |
|
Brokered natural gas and marketing, as reported |
|
69,564 |
|
|
|
46,532 |
|
|
|
188,316 |
|
|
|
359,892 |
|
Less brokered natural gas and marketing stock-based |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
compensation |
|
(511 |
) |
|
|
(333 |
) |
|
|
(1,416 |
) |
|
|
(1,856 |
) |
General and administrative, as reported |
|
40,720 |
|
|
|
42,793 |
|
|
|
159,415 |
|
|
|
181,109 |
|
Less G&A stock-based compensation |
|
(8,834 |
) |
|
|
(7,500 |
) |
|
|
(32,905 |
) |
|
|
(35,061 |
) |
Less lawsuit settlements |
|
(579 |
) |
|
|
(542 |
) |
|
|
(2,251 |
) |
|
|
(2,577 |
) |
Less rig release penalty |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(1,436 |
) |
Interest expense, as reported |
|
48,526 |
|
|
|
44,024 |
|
|
|
192,667 |
|
|
|
194,285 |
|
Less amortization of deferred financing costs |
|
(2,137 |
) |
|
|
(1,981 |
) |
|
|
(8,466 |
) |
|
|
(7,369 |
) |
Cash expenses |
|
423,371 |
|
|
|
464,790 |
|
|
|
1,699,546 |
|
|
|
2,058,599 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash margin, a
non-GAAP measure |
$ |
106,592 |
|
|
$ |
172,207 |
|
|
$ |
402,418 |
|
|
$ |
729,582 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mmcfe produced during
period |
|
192,067 |
|
|
|
215,757 |
|
|
|
816,456 |
|
|
|
833,354 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash margin per
mcfe |
$ |
0.55 |
|
|
$ |
0.80 |
|
|
$ |
0.49 |
|
|
$ |
0.88 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RECONCILIATION OF
INCOME (LOSS) BEFORE INCOMETAXES TO CASH
MARGIN |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited, in thousands,
except per unit data) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months EndedDecember 31, |
|
Twelve Months EndedDecember 31, |
|
2020 |
|
2019 |
|
2020 |
|
2019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before
income taxes, as reported |
$ |
42,626 |
|
|
$ |
(2,304,179 |
) |
|
$ |
(737,329 |
) |
|
$ |
(2,216,588 |
) |
Adjustments to
reconcile income (loss) before income taxes to cash
margin: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ARO settlements and other gains |
|
(780 |
) |
|
|
(151 |
) |
|
|
(1,651 |
) |
|
|
(1,137 |
) |
Derivative fair value (income) |
|
(85,529 |
) |
|
|
(18,491 |
) |
|
|
(187,711 |
) |
|
|
(226,681 |
) |
Net cash receipts on derivative settlements |
|
17,386 |
|
|
|
50,035 |
|
|
|
322,629 |
|
|
|
188,384 |
|
Exploration expense |
|
9,076 |
|
|
|
9,156 |
|
|
|
31,375 |
|
|
|
35,117 |
|
Lawsuit settlements |
|
579 |
|
|
|
542 |
|
|
|
2,251 |
|
|
|
2,577 |
|
Rig release penalty |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
1,436 |
|
Exit and termination costs |
|
13,739 |
|
|
|
4,535 |
|
|
|
545,244 |
|
|
|
7,535 |
|
Deferred compensation plan |
|
2,254 |
|
|
|
960 |
|
|
|
12,541 |
|
|
|
(15,472 |
) |
Stock-based compensation (direct operating, brokered natural gas
and marketing, general and administrative and termination
costs) |
|
10,146 |
|
|
|
10,442 |
|
|
|
38,843 |
|
|
|
42,382 |
|
Interest – amortization of deferred financing costs |
|
2,137 |
|
|
|
1,981 |
|
|
|
8,466 |
|
|
|
7,369 |
|
Depletion, depreciation and amortization |
|
90,551 |
|
|
|
130,869 |
|
|
|
394,330 |
|
|
|
548,843 |
|
Loss (gain) loss on sale of assets |
|
1,652 |
|
|
|
(407 |
) |
|
|
(110,791 |
) |
|
|
30,256 |
|
Loss (gain) on early extinguishment of debt |
|
25 |
|
|
|
(2,430 |
) |
|
|
(14,068 |
) |
|
|
(5,415 |
) |
Impairment of proved property and other assets |
|
— |
|
|
|
1,095,634 |
|
|
|
78,955 |
|
|
|
1,095,634 |
|
Abandonment and impairment of unproved properties |
|
2,730 |
|
|
|
1,193,711 |
|
|
|
19,334 |
|
|
|
1,235,342 |
|
Cash margin, a
non-GAAP measure |
$ |
106,592 |
|
|
$ |
172,207 |
|
|
$ |
402,418 |
|
|
$ |
729,582 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEE WEBSITE FOR OTHER SUPPLEMENTAL
INFORMATION AND HEDGING DETAILS
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