Centennial Resource Development, Inc. (“Centennial” or the
“Company”) (NASDAQ: CDEV) today announced 2020 financial and
operational results and 2021 operational plans and targets.
Financial and Operational Highlights
- Generated free cash flow and reduced total debt for the second
consecutive quarter
- Reported 2020 production volumes, capital expenditures and
total unit costs within full year guidance ranges
- Achieved record spud-to-total depth time for a two-mile
lateral
- Increased year-over-year acreage position primarily through
cost-free swaps and trades
2021 Financial and Operational Plan
- Expect to be free cash flow positive in 2021 using current
strip pricing
- Anticipate significant reduction in leverage by year-end
2021
- Plan to operate two-rig drilling program
- Expect to average full year oil production consistent with
fourth quarter 2020 levels
- Operational plan supported by structurally lower well costs and
increased lateral lengths
Financial Results
For the full year, Centennial reported a net
loss of $682.8 million, or $2.46 per diluted share,
driven primarily by a non-cash impairment charge incurred
during the first quarter in addition to historically low oil prices
during a portion of the year as a result of the COVID-19 pandemic.
Full year results compare to net income of $15.8 million, or $0.06
per diluted share, in the prior year. For the fourth quarter, the
Company reported a net loss of $88.7 million, or $0.32 per diluted
share, compared to net income of $9.6 million, or $0.03 per diluted
share, in the prior year period. As a result of higher realized
commodity prices and continued cost discipline, the Company
generated net cash from operating activities of $41.1 million and
free cash flow1 of $29.0 million in the fourth quarter of 2020.
Full year total equivalent production averaged
67,161 barrels of oil equivalent per day (“Boe/d”) compared to
76,072 Boe/d in the prior year. Average daily crude oil production
during the full year was 36,084 barrels of oil per day (“Bbls/d”)
compared to 42,692 Bbls/d in the prior year. For the fourth
quarter, crude oil production averaged 30,196 Bbls/d, in-line with
Company expectations as no new wells were placed on production
during the quarter.
“We added a second rig in December and are
excited to resume operational activity. Importantly, our team
continues to drive higher efficiencies in the field which will
remain a key focus for us in 2021,” said Sean R. Smith, Chief
Executive Officer. “Coupled with current strip pricing, our reduced
cost structure, lower well costs and shallower base decline rate
set us up for free cash flow generation this year. We expect to
organically de-lever the balance sheet and end the year in a
stronger financial position.”
2021 Operational Plans and
Targets
Centennial plans to operate a two-rig drilling
program in 2021. Assuming planned activity levels and current
commodity prices, the Company expects its full year average oil
production to remain largely consistent with fourth quarter 2020
levels. During 2021, Centennial will continue to focus on
managing its balance sheet and improving liquidity.
“Our capital plan will position Centennial to be
free cash flow positive, while improving our leverage metrics
during 2021,” said Smith. “Ultimately, we expect to end the year
with a net debt-to-LTM EBITDAX2 ratio below 2.5x, assuming current
strip pricing.”
The estimated fiscal year 2021 total capital
budget is approximately $260 million to $310 million. Total
drilling, completion and facilities (“DC&F”) costs are
estimated to be $250 million to $290 million, of which essentially
all is associated with operated activity. The Company’s capital
budget is underpinned by a 33% reduction in well costs compared to
year-end 2019. Lastly, Centennial has allocated approximately $10
million to $20 million to infrastructure, land and other capital
expenditures.
During 2021, Centennial anticipates that
approximately 70% of its completions will occur in Lea County, New
Mexico, with the remaining portion allocated to its Reeves County,
Texas position. Additionally, the Company expects its average
completed lateral length for the full year to increase 17% to
approximately 8,800 feet compared to the prior year, driving
further capital efficiency improvements.
(For a detailed table summarizing Centennial’s
2021 operational and financial guidance, please see the Appendix of
this press release.)
Recent Winter Weather
Impacts
The severe winter weather which recently
affected millions of Americans across Texas and other states also
impacted Centennial's employees and operations. While the Company
continues to assess developments in the field, Centennial recently
regained full electric power to its operations and is in the
process of placing wells back on production. As a result of these
events and the expected timing of operational activity, Centennial
expects its first quarter 2021 production levels to decline
compared to the previous quarter. The Company expects a modestly
increasing quarterly production profile for the remainder of the
year.
“Our employees and their families’ well-being
remain our top priority, and I would like to personally thank our
team members in the field for their hard work and dedication over
the past two weeks,” said Smith. “While the recent winter weather
and associated power outages significantly impacted our operations,
we now have the majority of our production back online and expect
to restore the remaining portion by the end of this week.”
Fourth Quarter Operational
Results
Centennial operated one drilling rig for a
majority of the fourth quarter and added a second drilling rig and
commenced completion activity in late December. The Company spud
seven wells during the quarter, which was higher than anticipated
due to drilling efficiencies.
“Our operations team continues to build upon the
efficiencies gained last year. During the fourth quarter, we set a
new Company drilling record, reaching spud-to-total depth on a
two-mile lateral in just under eight days,” said Smith. “These
reduced cycle times and structural cost reductions have driven a
material reduction in well costs and are evidenced by our
year-to-date 2021 completions, which consist of six wells with an
average gross cost of approximately $790 per lateral foot.”
Additionally, Centennial has placed a heightened
focus on reducing the volume of natural gas flared at its
production locations. During the fourth quarter, Centennial’s
flaring rate was 0.5% of total gross operated gas production. “Gas
capture will continue to be an ongoing priority, and for 2021, we
have set a flaring target of 1%,” said Smith.
Total capital expenditures incurred for the
quarter were $29.9 million. Fourth quarter drilling and completion
capital expenditures totaled $24.1 million and included higher
activity than originally anticipated due to continued drilling
efficiencies. The remaining $5.8 million was primarily spent on
facilities and infrastructure. For the full year, total capital
expenditures were $254.8 million, of which nearly 70% was incurred
in the first quarter.
Acreage Position Update
In 2020, Centennial increased its acreage
position by approximately 3,500 net acres primarily through
cost-free acreage swaps and trades, further adding high-quality
inventory to its portfolio. As of December 31, 2020, Centennial’s
Delaware Basin position totaled 81,657 net acres, which is
allocated between Texas (71%) and New Mexico (29%). During the
year, the Company increased its New Mexico position by 27% to
approximately 23,900 net acres. Notably, these additions were
comprised almost entirely of state and fee acreage. As a result,
the Company’s net acreage located on Federal lands is now
approximately 4% of its overall Delaware Basin position,
representing a slight reduction from the prior year.
Year-End 2020 Proved
Reserves
Centennial reported year-end 2020 total proved
reserves of 299 MMBoe compared to 301 MMBoe in the prior year. The
modest decrease from the prior year was primarily attributable to
lower SEC pricing, which was largely offset by the Company’s lower
DC&F and operating costs that resulted in significant reserve
additions during the year. At year-end 2020, proved reserves
consisted of 50% oil, 30% natural gas and 20% natural gas liquids.
Proved developed reserves were 149 MMBoe (50% of total proved
reserves) as of December 31, 2020. For 2020, Centennial’s organic
reserve replacement ratio was 91%. The Company’s 2020 proved
developed finding and development cost totaled $11.48 per Boe.
Centennial’s drill-bit finding and development cost was $13.53 per
Boe for 2020. Centennial had a standardized measure of discounted
future net cash flows of $1.2 billion at December 31, 2020.
The present value at 10% (“PV 10%”, a non-GAAP financial measure
reconciled within the Appendix) of Centennial’s total proved
reserves was also $1.2 billion at year-end.
Netherland Sewell & Associates, Inc., an
independent reserve engineering firm, prepared Centennial’s
year-end reserves estimates as of December 31, 2020. (For
additional information relating to our reserves, in addition to an
explanation of how we calculate and use the organic reserve
replacement ratio and finding and development costs, please see the
Appendix of this press release.)
Capital Structure and
Liquidity
During the quarter, the Company used a portion
of its operating cash flow to pay down $25 million in borrowings
under its credit facility. As of December 31, 2020, Centennial
had approximately $6 million in cash on hand and $330 million of
borrowings outstanding under its revolving credit facility. As a
result, Centennial’s total liquidity position increased by
approximately $25 million from the prior quarter to end the year at
$340 million, which is based on its $700 million borrowing base,
borrowings outstanding, the availability blocker of $32 million and
$4 million in current letters of credit outstanding, plus cash on
hand.
Hedge Position
For the full year 2021, Centennial has a total
of 14,595 Bbls/d of oil hedged, consisting of approximately 85%
fixed price swaps. For 2021, the Company currently has 9,734 Bbls/d
and 2,870 Bbls/d of oil hedged at weighted average fixed prices of
$43.70 per barrel WTI and $50.57 per barrel Brent, respectively.
Also for 2021, the Company has 1,990 Bbls/d of WTI oil collars in
place with a weighted average floor and ceiling price of $41.13 per
barrel and $49.58 per barrel, respectively. Notably, a majority of
the Company’s oil hedges is weighted towards the first half of
2021. Centennial’s oil production is currently unhedged in 2022 and
beyond. In addition, Centennial has certain crude oil basis swaps
in place for 2021 and certain natural gas hedges in place for 2021
and 2022. (For a summary table of Centennial’s derivative contracts
as of February 19, 2021, please see the Appendix to this press
release.)
Annual Report on Form 10-K
Centennial’s financial statements and related
footnotes will be available in its Annual Report on Form 10-K for
the year ended December 31, 2020, which is expected to be
filed with the U.S. Securities and Exchange Commission (“SEC”) on
February 24, 2021.
Conference Call and Webcast
Centennial will host an investor conference call
on Wednesday, February 24, 2021 at 8:00 a.m. Mountain (10:00 a.m.
Eastern) to discuss fourth quarter and full year 2020 operating and
financial results. Interested parties may join the webcast by
visiting Centennial’s website at www.cdevinc.com and clicking
on the webcast link or by dialing (844) 348-0017, or (213) 358-0877
for international calls, (Conference ID: 9171897) at least 15
minutes prior to the start of the call. A replay of the call will
be available on Centennial’s website or by phone at (855) 859-2056
(Conference ID: 9171897) for a seven day period following the
call.
About Centennial Resource Development,
Inc.
Centennial Resource Development, Inc. is an
independent oil and natural gas company focused on the development
of unconventional oil and associated liquids-rich natural gas
reserves in the Permian Basin. The Company’s assets and operations,
which are held and conducted through Centennial Resource
Production, LLC, are concentrated in the Delaware Basin, a
sub-basin of the Permian Basin. For additional information about
the Company, please visit www.cdevinc.com.
Cautionary Note Regarding
Forward-Looking Statements
The information in this press release includes
“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. All statements, other
than statements of historical fact included in this press release,
regarding our strategy, future operations, financial position,
estimated revenues and losses, projected costs, prospects, plans
and objectives of management are forward-looking statements. When
used in this press release, the words “could,” “may,” “believe,”
“anticipate,” “intend,” “estimate,” “expect,” “project,” “goal,”
“plan,” “target” and similar expressions are intended to identify
forward-looking statements, although not all forward-looking
statements contain such identifying words. These forward-looking
statements are based on management’s current expectations and
assumptions about future events and are based on currently
available information as to the outcome and timing of future
events.
Forward-looking statements may include
statements about:
- volatility of oil, natural gas and NGL prices or a prolonged
period of low oil, natural gas or NGL prices and the effects of
actions by, or disputes among or between, members of the
Organization of Petroleum Exporting Countries (“OPEC”), such as
Saudi Arabia, and other oil and natural gas producing countries,
such as Russia, with respect to production levels or other matters
related to the price of oil;
- the effects of excess supply of oil and natural gas resulting
from reduced demand caused by the COVID-19 pandemic and the actions
taken in response by certain oil and natural gas producing
countries;
- our business strategy and future drilling plans;
- our reserves and our ability to replace the reserves we produce
through drilling and property acquisitions;
- our drilling prospects, inventories, projects and
programs;
- our financial strategy, liquidity and capital required for our
development program;
- our realized oil, natural gas and NGL prices;
- the timing and amount of our future production of oil, natural
gas and NGLs;
- our hedging strategy and results;
- our competition and government regulations;
- our ability to obtain permits and governmental approvals;
- our pending legal or environmental matters;
- the marketing and transportation of our oil, natural gas and
NGLs;
- our leasehold or business acquisitions;
- cost of developing our properties;
- our anticipated rate of return;
- general economic conditions;
- weather conditions in the areas where we operate;
- credit markets;
- uncertainty regarding our future operating results;
- our plans, objectives, expectations and intentions contained in
this press release that are not historical; and
- the other factors described in our most recent Annual Report on
Form 10-K, and any updates to those factors set forth in our
subsequent Quarterly Reports on Form 10-Q or Current Reports on
Form 8-K.
We caution you that these forward-looking
statements are subject to all of the risks and uncertainties, most
of which are difficult to predict and many of which are beyond our
control, incident to the development, production, gathering and
sale of oil and natural gas. These risks include, but are not
limited to, commodity price volatility, inflation, lack of
availability of drilling and production equipment and services,
environmental risks, drilling and other operating risks, regulatory
changes, the uncertainty inherent in estimating oil and gas
reserves and in projecting future rates of production, cash flow
and access to capital, the timing of development expenditures and
the other risks described in our filings with the SEC.
Reserve engineering is a process of estimating
underground accumulations of oil and natural gas that cannot be
measured in an exact way. The accuracy of any oil and gas reserve
estimate depends on the quality of available data, the
interpretation of such data, and price and cost assumptions made by
reserve engineers. In addition, the results of drilling, testing
and production activities may justify revisions of estimates that
were made previously. If significant, such revisions would change
the schedule of any further production and development drilling.
Accordingly, reserve estimates may differ significantly from the
quantities of oil and natural gas that are ultimately
recovered.
Should one or more of the risks or uncertainties
described in this press release occur or should underlying
assumptions prove incorrect, our actual results and plans could
differ materially from those expressed in any forward-looking
statements. All forward-looking statements, expressed or implied,
included in this press release are expressly qualified in their
entirety by this cautionary statement. This cautionary statement
should also be considered in connection with any subsequent written
or oral forward-looking statements that we or persons acting on our
behalf may issue.
Except as otherwise required by applicable law,
we disclaim any duty to update any forward-looking statements, all
of which are expressly qualified by the statements in this section,
to reflect events or circumstances after the date of this press
release.
1) Free Cash Flow is a non-GAAP financial
measure. See “Non-GAAP Financial Measures” included within the
Appendix of this press release for related disclosures and a
reconciliation to net cash provided by operating activities, our
most directly comparable financial measure calculated and presented
in accordance with GAAP.
2) Net debt-to-LTM EBITDAX is a non-GAAP
financial measure. The Company defines net debt (reconciled in the
Appendix of this press release) as long-term debt, net, plus
unamortized debt discount and debt issuance costs on senior notes
minus cash and cash equivalents. The Company defines net
debt-to-LTM EBITDAX as net debt (defined above) divided by Adjusted
EBITDAX (defined and reconciled in the Appendix of this press
release) for the prior twelve-month period. The Company presents
this metric to show trends that investors may find useful in
understanding the Company's ability to service its debt. This
metric is widely used by professional research analysts, including
credit analysts, in the valuation and comparison of companies in
the oil and gas exploration and production industry. Centennial
does not provide guidance on the items used to reconcile between
forecasted net debt-to-LTM EBITDAX to forecasted long-term debt,
net, or forecasted net income due to the uncertainty regarding
timing and estimates of certain items; therefore, Centennial cannot
reconcile forecasted net debt-to-LTM EBITDAX to forecasted
long-term debt, net, or forecasted net income without unreasonable
effort.
Contact:Hays MabryDirector,
Investor Relations(832) 240-3265ir@cdevinc.com
Details of our 2021 operational and financial
guidance are presented below:
|
2021 FY Guidance |
Net average daily production (Boe/d) |
56,000 |
— |
63,000 |
Net average daily oil
production (Bbls/d) |
29,700 |
— |
32,700 |
|
|
|
|
Production
costs |
|
|
|
Lease operating expenses
($/Boe) |
$4.50 |
— |
$5.10 |
Gathering, processing and
transportation expenses ($/Boe) |
$3.00 |
— |
$3.40 |
Depreciation, depletion, and
amortization ($/Boe) |
$13.00 |
— |
$15.00 |
Cash general and
administrative ($/Boe)1 |
$1.95 |
— |
$2.25 |
Stock-based compensation
($/Boe)2 |
$1.50 |
— |
$2.00 |
Severance and ad valorem taxes
(% of revenue) |
6.0% |
— |
8.0% |
|
|
|
|
Capital expenditure
program ($MM) |
$260 |
— |
$310 |
Drilling, completion and
facilities |
$250 |
— |
$290 |
Infrastructure, land and
other |
$10 |
— |
$20 |
|
|
|
|
Operated drilling
program |
|
|
|
Wells spud (gross) |
40 |
— |
46 |
Wells completed (gross) |
40 |
— |
48 |
Average working interest |
~85% |
Average lateral length
(feet) |
~8,800 |
(1) Cash general and
administrative guidance does not include the portion of stock-based
compensation that will settle in cash.
(2) Stock-based compensation
guidance includes expense amounts for both equity awards and for
cash-based liability awards. The amount of actual expense to be
incurred for the liability awards included in this guidance range
may vary from our forecast, as such expense can fluctuate
materially in future periods with changes in Centennial’s stock
price and, for certain awards, with changes in Centennial’s stock
price performance versus a defined peer group of companies. A
portion of these liability awards are expected to be paid in cash
during fiscal year 2021.
Centennial Resource Development,
Inc.Operating Highlights
|
Three Months Ended December 31, |
|
Year Ended December 31, |
|
2020 |
|
2019 |
|
2020 |
|
2019 |
Net revenues (in
thousands): |
|
|
|
|
|
|
|
Oil sales |
$ |
112,123 |
|
|
$ |
220,600 |
|
|
$ |
475,694 |
|
|
$ |
810,655 |
|
Natural gas sales |
17,724 |
|
|
12,901 |
|
|
46,776 |
|
|
44,556 |
|
NGL sales |
18,230 |
|
|
22,891 |
|
|
57,986 |
|
|
89,119 |
|
Oil and gas sales |
$ |
148,077 |
|
|
$ |
256,392 |
|
|
$ |
580,456 |
|
|
$ |
944,330 |
|
|
|
|
|
|
|
|
|
Average sales
price: |
|
|
|
|
|
|
|
Oil (per Bbl) |
$ |
40.36 |
|
|
$ |
53.25 |
|
|
$ |
36.02 |
|
|
$ |
52.02 |
|
Effect of derivative settlements on average price (per Bbl) |
(1.54 |
) |
|
(1.09 |
) |
|
(3.15 |
) |
|
(1.13 |
) |
Oil net of hedging (per Bbl) |
$ |
38.82 |
|
|
$ |
52.16 |
|
|
$ |
32.87 |
|
|
$ |
50.89 |
|
|
|
|
|
|
|
|
|
Average NYMEX price for oil (per Bbl) |
$ |
42.66 |
|
|
$ |
56.94 |
|
|
$ |
39.44 |
|
|
$ |
57.03 |
|
Oil differential from NYMEX |
(2.30 |
) |
|
(3.69 |
) |
|
(3.42 |
) |
|
(5.01 |
) |
|
|
|
|
|
|
|
|
Natural gas (per Mcf) |
$ |
1.76 |
|
|
$ |
1.14 |
|
|
$ |
1.13 |
|
|
$ |
1.07 |
|
Effect of derivative settlements on average price (per Mcf) |
(0.09 |
) |
|
0.09 |
|
|
(0.12 |
) |
|
0.29 |
|
Natural gas net of hedging (per Mcf) |
$ |
1.67 |
|
|
$ |
1.23 |
|
|
$ |
1.01 |
|
|
$ |
1.36 |
|
|
|
|
|
|
|
|
|
Average NYMEX price for natural gas (per Mcf) |
$ |
2.47 |
|
|
$ |
2.34 |
|
|
$ |
1.99 |
|
|
$ |
2.52 |
|
Natural gas differential from NYMEX |
(0.71 |
) |
|
(1.20 |
) |
|
(0.86 |
) |
|
(1.45 |
) |
|
|
|
|
|
|
|
|
NGL (per Bbl) |
$ |
17.65 |
|
|
17.47 |
|
|
$ |
12.91 |
|
|
$ |
17.03 |
|
|
|
|
|
|
|
|
|
Net
production: |
|
|
|
|
|
|
|
Oil (MBbls) |
2,778 |
|
|
4,142 |
|
|
13,207 |
|
|
15,582 |
|
Natural gas (MMcf) |
10,093 |
|
|
11,294 |
|
|
41,302 |
|
|
41,703 |
|
NGL (MBbls) |
1,032 |
|
|
1,311 |
|
|
4,490 |
|
|
5,234 |
|
Total (MBoe)(1) |
5,493 |
|
|
7,335 |
|
|
24,581 |
|
|
27,766 |
|
|
|
|
|
|
|
|
|
Average daily net
production: |
|
|
|
|
|
|
|
Oil (Bbls/d) |
30,196 |
|
|
45,031 |
|
|
36,084 |
|
|
42,692 |
|
Natural gas (Mcf/d) |
109,712 |
|
|
122,759 |
|
|
112,848 |
|
|
114,254 |
|
NGL (Bbls/d) |
11,226 |
|
|
14,242 |
|
|
12,269 |
|
|
14,338 |
|
Total (Boe/d)(1) |
59,708 |
|
|
79,734 |
|
|
67,161 |
|
|
76,072 |
|
_______________
(1) Calculated by converting natural gas to
oil equivalent barrels at a ratio of six Mcf of natural gas to one
Boe.
Centennial Resource Development,
Inc.Operating Expenses
|
Three Months Ended December 31, |
|
Year Ended December 31, |
|
2020 |
|
2019 |
|
2020 |
|
2019 |
Operating costs (in
thousands): |
|
|
|
|
|
|
|
Lease operating expenses |
$ |
26,261 |
|
$ |
38,899 |
|
$ |
109,282 |
|
$ |
145,976 |
Severance and ad valorem taxes |
9,309 |
|
17,681 |
|
39,417 |
|
63,200 |
Gathering, processing, and transportation expense |
17,956 |
|
20,714 |
|
71,309 |
|
72,834 |
Operating costs per
Boe: |
|
|
|
|
|
|
|
Lease operating expenses |
$ |
4.78 |
|
$ |
5.30 |
|
$ |
4.45 |
|
$ |
5.26 |
Severance and ad valorem taxes |
1.69 |
|
2.41 |
|
1.60 |
|
2.28 |
Gathering, processing, and transportation expense |
3.27 |
|
2.82 |
|
2.90 |
|
2.62 |
Centennial Resource Development,
Inc.Consolidated Statements of
Operations(in thousands, except per share
data)
|
Three Months Ended December 31, |
|
Year Ended December 31, |
|
2020 |
|
2019 |
|
2020 |
|
2019 |
Operating revenues |
|
|
|
|
|
|
|
Oil and gas sales |
$ |
148,077 |
|
|
$ |
256,392 |
|
|
$ |
580,456 |
|
|
$ |
944,330 |
|
Operating expenses |
|
|
|
|
|
|
|
Lease operating expenses |
26,261 |
|
|
38,899 |
|
|
109,282 |
|
|
145,976 |
|
Severance and ad valorem taxes |
9,309 |
|
|
17,681 |
|
|
39,417 |
|
|
63,200 |
|
Gathering, processing and transportation expenses |
17,956 |
|
|
20,714 |
|
|
71,309 |
|
|
72,834 |
|
Depreciation, depletion and amortization |
74,832 |
|
|
122,851 |
|
|
358,554 |
|
|
444,243 |
|
Impairment and abandonment expense |
40,561 |
|
|
4,818 |
|
|
691,190 |
|
|
47,245 |
|
Exploration and other expenses |
7,625 |
|
|
2,144 |
|
|
18,355 |
|
|
11,390 |
|
General and administrative expenses |
18,421 |
|
|
22,567 |
|
|
72,867 |
|
|
79,156 |
|
Total operating expenses |
194,965 |
|
|
229,674 |
|
|
1,360,974 |
|
|
864,044 |
|
Net gain (loss) on sale of
long-lived assets |
10 |
|
|
(842 |
) |
|
398 |
|
|
(857 |
) |
Income (loss) from
operations |
(46,878 |
) |
|
25,876 |
|
|
(780,120 |
) |
|
79,429 |
|
|
|
|
|
|
|
|
|
Other income (expense) |
|
|
|
|
|
|
|
Interest expense |
(17,682 |
) |
|
(16,148 |
) |
|
(69,192 |
) |
|
(55,991 |
) |
Gain on exchange of debt |
— |
|
|
— |
|
|
143,443 |
|
|
— |
|
Net gain (loss) on derivative instruments |
(24,205 |
) |
|
660 |
|
|
(64,535 |
) |
|
(1,561 |
) |
Other income (expense) |
110 |
|
|
13 |
|
|
81 |
|
|
334 |
|
Total other income (expense) |
(41,777 |
) |
|
(15,475 |
) |
|
9,797 |
|
|
(57,218 |
) |
|
|
|
|
|
|
|
|
Income (loss) before income
taxes |
(88,655 |
) |
|
10,401 |
|
|
(770,323 |
) |
|
22,211 |
|
Income tax (expense)
benefit |
— |
|
|
(739 |
) |
|
85,124 |
|
|
(5,797 |
) |
Net income (loss) |
(88,655 |
) |
|
9,662 |
|
|
(685,199 |
) |
|
16,414 |
|
Less: Net (income) loss
attributable to noncontrolling interest |
— |
|
|
(44 |
) |
|
2,362 |
|
|
(616 |
) |
Net income (loss) attributable
to Class A Common Stock |
$ |
(88,655 |
) |
|
$ |
9,618 |
|
|
$ |
(682,837 |
) |
|
$ |
15,798 |
|
|
|
|
|
|
|
|
|
Income (loss) per share of
Class A Common Stock: |
|
|
|
|
|
|
|
Basic |
$ |
(0.32 |
) |
|
$ |
0.03 |
|
|
$ |
(2.46 |
) |
|
$ |
0.06 |
|
Diluted |
$ |
(0.32 |
) |
|
$ |
0.03 |
|
|
$ |
(2.46 |
) |
|
$ |
0.06 |
|
Centennial Resource Development,
Inc.Consolidated Balance
Sheets(in thousands, except share
and per share amounts)
|
December 31, 2020 |
|
December 31, 2019 |
ASSETS |
|
|
|
Current assets |
|
|
|
Cash and cash equivalents |
$ |
5,800 |
|
|
$ |
10,223 |
|
Accounts receivable, net |
54,557 |
|
|
101,912 |
|
Prepaid and other current assets |
5,229 |
|
|
7,994 |
|
Total current assets |
65,586 |
|
|
120,129 |
|
Property and Equipment |
|
|
|
Oil and natural gas properties, successful efforts method |
|
|
|
Unproved properties |
1,209,205 |
|
|
1,470,903 |
|
Proved properties |
4,395,473 |
|
|
3,962,175 |
|
Accumulated depreciation, depletion and amortization |
(1,877,832 |
) |
|
(931,737 |
) |
Total oil and natural gas properties, net |
3,726,846 |
|
|
4,501,341 |
|
Other property and equipment, net |
12,650 |
|
|
14,612 |
|
Total property and equipment, net |
3,739,496 |
|
|
4,515,953 |
|
Noncurrent assets |
|
|
|
Operating lease right-of-use assets |
3,176 |
|
|
11,841 |
|
Other noncurrent assets |
19,167 |
|
|
40,365 |
|
TOTAL ASSETS |
$ |
3,827,425 |
|
|
$ |
4,688,288 |
|
|
|
|
|
LIABILITIES AND
EQUITY |
|
|
|
Current liabilities |
|
|
|
Accounts payable and accrued expenses |
$ |
110,439 |
|
|
$ |
244,309 |
|
Operating lease liabilities |
3,155 |
|
|
9,232 |
|
Other current liabilities |
18,274 |
|
|
925 |
|
Total current liabilities |
131,868 |
|
|
254,466 |
|
Noncurrent liabilities |
|
|
|
Long-term debt, net |
1,068,624 |
|
|
1,057,389 |
|
Asset retirement obligations |
17,009 |
|
|
16,874 |
|
Deferred income taxes |
2,589 |
|
|
85,504 |
|
Operating lease liabilities |
422 |
|
|
3,354 |
|
Other noncurrent liabilities |
2,952 |
|
|
— |
|
Total liabilities |
1,223,464 |
|
|
1,417,587 |
|
|
|
|
|
Shareholders’ equity |
|
|
|
Preferred stock, $.0001 par value, 1,000,000 shares
authorized: |
|
|
|
Series A: No shares issued and outstanding at December 31, 2020 and
1 share issued and outstanding at December 31, 2019 |
— |
|
|
— |
|
Common stock, $0.0001 par value, 620,000,000 shares
authorized: |
|
|
|
Class A: 290,645,623 shares issued and 278,551,901 shares
outstanding at December 31, 2020 and 280,650,341 shares issued and
275,811,346 shares outstanding at December 31, 2019 |
29 |
|
|
28 |
|
Class C (Convertible): No shares issued and outstanding at December
31, 2020 and 1,034,119 shares issued and outstanding at December
31, 2019 |
— |
|
|
— |
|
Additional paid-in capital |
3,004,433 |
|
|
2,975,756 |
|
Retained earnings (accumulated deficit) |
(400,501 |
) |
|
282,336 |
|
Total shareholders’ equity |
2,603,961 |
|
|
3,258,120 |
|
Noncontrolling interest |
— |
|
|
12,581 |
|
Total equity |
2,603,961 |
|
|
3,270,701 |
|
TOTAL LIABILITIES AND EQUITY |
$ |
3,827,425 |
|
|
$ |
4,688,288 |
|
Centennial Resource Development,
Inc.Consolidated Statements of Cash
Flows(in thousands)
|
Year Ended December 31, |
|
2020 |
|
2019 |
Cash flows from
operating activities: |
|
|
|
Net income (loss) |
$ |
(685,199 |
) |
|
$ |
16,414 |
|
Adjustments to reconcile net income to net cash provided by
operating activities: |
|
|
|
Depreciation, depletion and amortization |
358,554 |
|
|
444,243 |
|
Stock-based compensation expense - equity awards |
20,966 |
|
|
28,997 |
|
Impairment and abandonment expense |
691,190 |
|
|
47,245 |
|
Exploratory dry hole costs |
6,615 |
|
|
— |
|
Deferred tax expense (benefit) |
(85,124 |
) |
|
5,797 |
|
Net (gain) loss on sale of long-lived assets |
(398 |
) |
|
857 |
|
Non-cash portion of derivative (gain) loss |
17,884 |
|
|
(4,094 |
) |
Amortization of debt issuance costs and discount |
5,923 |
|
|
2,861 |
|
Gain on exchange of debt |
(143,443 |
) |
|
— |
|
Changes in operating assets and liabilities: |
|
|
|
(Increase) decrease in accounts receivable |
44,572 |
|
|
(10,098 |
) |
(Increase) decrease in prepaid and other assets |
(3,804 |
) |
|
(1,882 |
) |
Increase (decrease) in accounts payable and other liabilities |
(56,360 |
) |
|
33,833 |
|
Net cash provided by operating activities |
171,376 |
|
|
564,173 |
|
Cash flows from
investing activities: |
|
|
|
Acquisition of oil and natural gas properties |
(8,464 |
) |
|
(103,709 |
) |
Drilling and development capital expenditures |
(318,465 |
) |
|
(855,153 |
) |
Purchases of other property and equipment |
(1,083 |
) |
|
(8,857 |
) |
Proceeds from sales of oil and natural gas properties |
1,689 |
|
|
34,730 |
|
Net cash used in investing activities |
(326,323 |
) |
|
(932,989 |
) |
Cash flows from
financing activities: |
|
|
|
Proceeds from borrowings under revolving credit facility |
570,000 |
|
|
595,000 |
|
Repayment of borrowings under revolving credit facility |
(415,000 |
) |
|
(720,000 |
) |
Proceeds from issuance of senior notes |
— |
|
|
496,175 |
|
Debt exchange and debt issuance costs |
(6,650 |
) |
|
(7,200 |
) |
Restricted stock used for tax withholdings |
(607 |
) |
|
(1,038 |
) |
Net cash provided by financing activities |
147,743 |
|
|
362,937 |
|
Net increase (decrease) in
cash, cash equivalents and restricted cash |
(7,204 |
) |
|
(5,879 |
) |
Cash, cash equivalents and
restricted cash, beginning of period |
15,543 |
|
|
21,422 |
|
Cash, cash equivalents
and restricted cash, end of period |
$ |
8,339 |
|
|
$ |
15,543 |
|
Reconciliation of cash, cash equivalents and
restricted cash presented on the consolidated statements of cash
flows for the periods presented:
|
Year Ended December 31, |
|
2020 |
|
2019 |
Cash and cash equivalents |
$ |
5,800 |
|
|
$ |
10,223 |
|
Restricted cash |
$ |
2,539 |
|
|
$ |
5,320 |
|
Total cash, cash equivalents
and restricted cash |
$ |
8,339 |
|
|
$ |
15,543 |
|
Non-GAAP Financial MeasuresIn
addition to disclosing financial results calculated in accordance
with U.S. generally accepted accounting principles (“GAAP”), our
earnings release contains non-GAAP financial measures as described
below.
Adjusted EBITDAX
Adjusted EBITDAX is a supplemental non-GAAP
financial measure that is used by management and external users of
our consolidated financial statements, such as industry analysts,
investors, lenders and rating agencies. We define Adjusted EBITDAX
as net income before interest expense, income taxes, depreciation,
depletion and amortization, exploration and other expenses,
impairment and abandonment expenses, non-cash gains or losses on
derivatives, stock-based compensation, gain on exchange of debt,
gains and losses from the sale of assets, transaction costs and
nonrecurring workforce reduction severance payments. Adjusted
EBITDAX is not a measure of net income as determined by GAAP.
Our management believes Adjusted EBITDAX is
useful as it allows them to more effectively evaluate our operating
performance and compare the results of our operations from period
to period and against our peers, without regard to our financing
methods or capital structure. We exclude the items listed above
from net income in arriving at Adjusted EBITDAX because these
amounts can vary substantially from company to company within our
industry depending upon accounting methods and book values of
assets, capital structures and the method by which the assets were
acquired. Adjusted EBITDAX should not be considered as an
alternative to, or more meaningful than, net income as determined
in accordance with GAAP or as an indicator of our operating
performance or liquidity. Certain items excluded from Adjusted
EBITDAX are significant components in understanding and assessing a
company’s financial performance, such as a company’s cost of
capital and tax structure, as well as the historic costs of
depreciable assets, none of which are components of Adjusted
EBITDAX. Our presentation of Adjusted EBITDAX should not be
construed as an inference that our results will be unaffected by
unusual or nonrecurring items. Our computations of Adjusted EBITDAX
may not be comparable to other similarly titled measures of other
companies.
The following table presents a reconciliation of
Adjusted EBITDAX to net income, which is the most directly
comparable financial measure calculated and presented in accordance
with GAAP:
|
Three Months Ended December 31, |
|
Year Ended December 31, |
(in
thousands) |
2020 |
|
2019 |
|
2020 |
|
2019 |
Adjusted EBITDAX
reconciliation to net income: |
|
|
|
|
|
|
|
Net income (loss) attributable to Class A Common Stock |
$ |
(88,655 |
) |
|
$ |
9,618 |
|
|
$ |
(682,837 |
) |
|
$ |
15,798 |
|
Net income (loss) attributable
to noncontrolling interest |
— |
|
|
44 |
|
|
(2,362 |
) |
|
616 |
|
Interest expense |
17,682 |
|
|
16,148 |
|
|
69,192 |
|
|
55,991 |
|
Income tax expense
(benefit) |
— |
|
|
739 |
|
|
(85,124 |
) |
|
5,797 |
|
Depreciation, depletion and
amortization |
74,832 |
|
|
122,851 |
|
|
358,554 |
|
|
444,243 |
|
Impairment and abandonment
expense |
40,561 |
|
|
4,818 |
|
|
691,190 |
|
|
47,245 |
|
Gain on exchange of debt |
— |
|
|
— |
|
|
(143,443 |
) |
|
— |
|
Non-cash derivative (gain)
loss |
18,987 |
|
|
(4,108 |
) |
|
17,884 |
|
|
(4,094 |
) |
Stock-based compensation
expense(1) |
8,111 |
|
|
6,998 |
|
|
23,045 |
|
|
26,315 |
|
Exploration and other
expenses |
7,625 |
|
|
2,144 |
|
|
18,355 |
|
|
11,390 |
|
Workforce reduction severance
payments |
— |
|
|
— |
|
|
3,466 |
|
|
— |
|
Transaction costs |
— |
|
|
— |
|
|
476 |
|
|
— |
|
(Gain) loss on sale of
long-lived assets |
(10 |
) |
|
842 |
|
|
(398 |
) |
|
857 |
|
Adjusted EBITDAX |
$ |
79,133 |
|
|
$ |
160,094 |
|
|
$ |
267,998 |
|
|
$ |
604,158 |
|
(1) Includes stock-based compensation for
equity awards and also for cash-based liability awards that have
not yet been settled in cash, both of which relate to general and
administrative employees only. Stock-based compensation amounts for
geographical and geophysical personnel are included within the
Exploration and other expenses line item.
Free Cash Flow (Deficit)
Free cash flow (deficit) is a supplemental
non-GAAP financial measure that is used by management and external
users of our consolidated financial statements, such as industry
analysts, investors, lenders and rating agencies. We define free
cash flow (deficit) as net cash provided by operating activities
before changes in working capital, less incurred capital
expenditures.
Our management believes free cash flow (deficit)
is a useful indicator of the Company’s ability to internally fund
its exploration and development activities and to service or incur
additional debt, without regard to the timing of settlement of
either operating assets and liabilities or accounts payable related
to capital expenditures. The Company believes that this measure, as
so adjusted, presents a meaningful indicator of the Company’s
actual sources and uses of capital associated with its operations
conducted during the applicable period. Our computations of free
cash flow (deficit) may not be comparable to other similarly titled
measures of other companies. Free cash flow (deficit) should not be
considered as an alternative to, or more meaningful than, cash
provided by operating activities as determined in accordance with
GAAP or as indicator of our operating performance or liquidity.
Free cash flow (deficit) is not a financial
measure that is determined in accordance with GAAP. Accordingly,
the following table presents a reconciliation of free cash flow
(deficit) to net cash provided by operating activities, which is
the most directly comparable financial measure calculated and
presented in accordance with GAAP:
|
Three Months Ended December 31, |
(in
thousands) |
2020 |
|
2019 |
Net cash provided by operating activities |
$ |
41,144 |
|
|
$ |
179,298 |
|
Changes in working
capital: |
|
|
|
Accounts receivable |
3,567 |
|
|
(37,673 |
) |
Prepaid and other assets |
979 |
|
|
887 |
|
Accounts payable and other liabilities |
13,253 |
|
|
729 |
|
Discretionary cash flow |
58,943 |
|
|
143,241 |
|
Less: total capital
expenditures incurred |
(29,900 |
) |
|
(197,100 |
) |
Free cash flow (deficit) |
$ |
29,043 |
|
|
$ |
(53,859 |
) |
Net Debt / Book Capitalization
Ratio
Net debt / book capitalization ratio is a
supplemental non-GAAP financial measure that is used by management
and external users of our consolidated financial statements, such
as industry analysts, investors, lenders and rating agencies. We
define net debt / book capitalization ratio as net debt divided by
book capitalization (non-GAAP). Net debt is defined as long-term
debt, net, plus unamortized debt discount and debt issuance costs
on senior notes minus cash and cash equivalents. Book
capitalization (non-GAAP) is defined as long-term debt, net, plus
unamortized debt discount and issuance costs on senior notes, plus
total equity. Net debt / book capitalization ratio is not a measure
calculated in accordance with GAAP.
Our management believes net debt / book
capitalization ratio is useful as it allows them to more
effectively evaluate our capital structure and liquidity and
compare the results against our peers. Net debt / book
capitalization ratio should not be considered as an alternative to,
or more meaningful than, debt / book capitalization (GAAP) as
determined in accordance with GAAP or as an indicator of our
operating performance or liquidity. Our computations of net debt /
book capital ratio may not be comparable to other similarly titled
measures of other companies.
The following table presents a reconciliation of
our net debt / book capitalization ratio to our most directly
comparable financial measure calculated and presented in accordance
with GAAP:
(in
thousands) |
|
December 31, 2020 |
|
December 31, 2019 |
Total equity |
|
$ |
2,603,961 |
|
|
$ |
3,270,701 |
|
|
|
|
|
|
Long-term debt, net |
|
1,068,624 |
|
|
1,057,389 |
|
Unamortized debt discount and
debt issuance costs on senior notes |
|
34,248 |
|
|
17,611 |
|
Long-term debt |
|
1,102,872 |
|
|
1,075,000 |
|
Less: cash and cash
equivalents |
|
(5,800 |
) |
|
(10,223 |
) |
Net debt (Non-GAAP) |
|
1,097,072 |
|
|
1,064,777 |
|
|
|
|
|
|
Book capitalization
(GAAP)(1) |
|
$ |
3,672,585 |
|
|
$ |
4,328,090 |
|
|
|
|
|
|
Book capitalization
(non-GAAP)(2) |
|
$ |
3,706,833 |
|
|
$ |
4,345,701 |
|
|
|
|
|
|
Debt / book capitalization
(GAAP)(3) |
|
29 |
% |
|
24 |
% |
|
|
|
|
|
Net debt / book capitalization
(non-GAAP)(4) |
|
30 |
% |
|
25 |
% |
_____________
(1) Book capitalization (GAAP) is
calculated as total equity plus long-term debt, net.
(2) Book capitalization (non-GAAP) is
calculated as total equity plus long-term debt.
(3) Debt / book capitalization (GAAP) is
calculated as long-term debt, net divided by book capitalization
(GAAP).
(4) Net debt / book capitalization (non-GAAP)
is calculated as net debt (non-GAAP) divided by book capitalization
(non-GAAP).
The following table summarizes the approximate volumes and
average contract prices of the hedge contracts the Company had in
place as of December 31, 2020 and additional contracts entered
into through February 19, 2021:
|
Period |
|
Volume (Bbls) |
|
Volume (Bbls/d) |
|
Wtd. Avg. Crude Price ($/Bbl)(1) |
Crude oil swaps |
|
|
|
|
|
|
|
NYMEX WTI |
January 2021 - March 2021 |
|
990,000 |
|
11,000 |
|
|
$41.48 |
|
April 2021 - June 2021 |
|
1,183,000 |
|
13,000 |
|
|
43.18 |
|
July 2021 - September 2021 |
|
736,000 |
|
8,000 |
|
|
45.87 |
|
October 2021 - December 2021 |
|
644,000 |
|
7,000 |
|
|
45.59 |
|
|
|
|
|
|
|
|
ICE Brent |
January 2021 - March 2021 |
|
270,000 |
|
3,000 |
|
|
$46.85 |
|
April 2021 - June 2021 |
|
409,500 |
|
4,500 |
|
|
54.98 |
|
July 2021 - September 2021 |
|
184,000 |
|
2,000 |
|
|
48.25 |
|
October 2021 - December 2021 |
|
184,000 |
|
2,000 |
|
|
48.50 |
|
|
|
|
|
|
|
|
|
Period |
|
Volume (Bbls) |
|
Volume (Bbls/d) |
|
Wtd. Avg. Collar Price Ranges
($/Bbl)(2) |
Crude oil collars |
January 2021 - March 2021 |
|
315,000 |
|
|
3,500 |
|
|
$40.00 - $48.14 |
|
April 2021 - June 2021 |
|
227,500 |
|
|
2,500 |
|
|
42.00 - 51.14 |
|
July 2021 - September 2021 |
|
92,000 |
|
|
1,000 |
|
|
42.00 - 50.10 |
|
October 2021 - December 2021 |
|
92,000 |
|
|
1,000 |
|
|
42.00 - 50.10 |
|
|
|
|
|
|
|
|
|
Period |
|
Volume (Bbls) |
|
Volume (Bbls/d) |
|
Wtd. Avg. Differential ($/Bbl)(3) |
Crude oil basis differential
swaps |
January 2021 - March 2021 |
|
990,000 |
|
11,000 |
|
|
$0.01 |
|
April 2021 - June 2021 |
|
1,183,000 |
|
13,000 |
|
|
0.11 |
|
July 2021 - September 2021 |
|
736,000 |
|
8,000 |
|
|
0.26 |
|
October 2021 - December 2021 |
|
644,000 |
|
7,000 |
|
|
0.26 |
_____________
(1) These crude oil swap transactions are
settled based on the NYMEX WTI or ICE Brent oil price on each
trading day within the specified monthly settlement period versus
the contractual swap price for the volumes stipulated.
(2) These crude oil collars are settled based
on the NYMEX WTI price on each trading day within the specified
monthly settlement period versus the contractual floor and ceiling
prices for the volumes stipulated.
(3) These oil basis swap transactions
are settled based on the difference between the arithmetic average
of ARGUS MIDLAND WTI and ARGUS WTI CUSHING indices, during each
applicable monthly settlement period.
|
Period |
|
Volume (MMBtu) |
|
Volume (MMBtu/d) |
|
Wtd Avg. Gas Price
($/MMBtu)(1) |
Natural gas swaps |
January 2021 - March 2021 |
|
5,400,000 |
|
60,000 |
|
|
$2.91 |
|
April 2021 - June 2021 |
|
3,640,000 |
|
40,000 |
|
|
2.89 |
|
July 2021 - September 2021 |
|
3,680,000 |
|
40,000 |
|
|
2.89 |
|
October 2021 - December 2021 |
|
3,680,000 |
|
40,000 |
|
|
2.95 |
|
January 2022 - March 2022 |
|
1,800,000 |
|
20,000 |
|
|
3.00 |
|
|
|
|
|
|
|
|
|
Period |
|
Volume (MMBtu) |
|
Volume (MMBtu/d) |
|
Wtd. Avg. Collar Price Ranges
($/MMBtu)(2) |
Natural gas collars |
January 2021 - March 2021 |
|
1,800,000 |
|
20,000 |
|
|
$2.90 - $3.64 |
|
|
|
|
|
|
|
|
|
Period |
|
Volume (MMBtu) |
|
Volume (MMBtu/d) |
|
Wtd. Avg. Differential
($/MMBtu)(3) |
Natural gas basis differential
swaps |
January 2021 - March 2021 |
|
1,800,000 |
|
20,000 |
|
|
$(0.30) |
|
April 2021 - June 2021 |
|
3,640,000 |
|
40,000 |
|
|
(0.30) |
|
July 2021 - September 2021 |
|
3,680,000 |
|
40,000 |
|
|
(0.30) |
|
October 2021 - December 2021 |
|
3,680,000 |
|
40,000 |
|
|
(0.28) |
|
January 2022 - March 2022 |
|
1,800,000 |
|
20,000 |
|
|
(0.26) |
_______________
(1) These natural gas swap contracts are
settled based on the NYMEX Henry Hub price on each trading day
within the specified monthly settlement period versus the
contractual swap price for the volumes stipulated.
(2) These natural gas collars are settled
based on the NYMEX Henry Hub price on each trading day within the
specified monthly settlement period versus the contractual floor
and ceiling prices for the volumes stipulated.
(3) These natural gas basis swap contracts are
settled based on the difference between the Inside FERC’s West
Texas WAHA price and the NYMEX price of natural gas, during each
applicable monthly settlement period.
The following table summarizes estimated proved
reserves, pre-tax PV 10%, and standardized measure of discounted
future cash flows as of the periods indicated:
|
December 31, 2020 |
|
December 31, 2019 |
|
December 31, 2018 |
Proved developed
reserves: |
|
|
|
|
|
Oil (MBbls) |
70,716 |
|
|
74,842 |
|
|
63,317 |
|
Natural gas (MMcf) |
279,556 |
|
|
237,791 |
|
|
180,542 |
|
NGL (MBbls) |
31,672 |
|
|
32,743 |
|
|
23,093 |
|
Total proved developed reserves (MBoe)(1) |
148,981 |
|
|
147,216 |
|
|
116,500 |
|
Proved undeveloped
reserves: |
|
|
|
|
|
Oil (MBbls) |
79,776 |
|
|
75,317 |
|
|
79,449 |
|
Natural gas (MMcf) |
248,231 |
|
|
264,639 |
|
|
222,310 |
|
NGL (MBbls) |
28,773 |
|
|
34,499 |
|
|
28,825 |
|
Total proved undeveloped reserves (MBoe)(1) |
149,921 |
|
|
153,923 |
|
|
145,326 |
|
Total proved
reserves: |
|
|
|
|
|
Oil (MBbls) |
150,492 |
|
|
150,159 |
|
|
142,766 |
|
Natural gas (MMcf) |
527,787 |
|
|
502,430 |
|
|
402,852 |
|
NGL (MBbls) |
60,445 |
|
|
67,242 |
|
|
51,918 |
|
Total proved reserves (MBoe)(1) |
298,902 |
|
|
301,139 |
|
|
261,826 |
|
|
|
|
|
|
|
Proved developed reserves
% |
50 |
% |
|
49 |
% |
|
44 |
% |
Proved undeveloped reserves
% |
50 |
% |
|
51 |
% |
|
56 |
% |
|
|
|
|
|
|
Reserve values (in
millions): |
|
|
|
|
|
Standard measure of discounted future net cash flows |
$ |
1,184.7 |
|
|
$ |
2,062.4 |
|
|
$ |
2,479.9 |
|
Discounted future income tax expense |
4.4 |
|
|
135.5 |
|
|
499.6 |
|
Total proved pre-tax PV 10%(2) |
$ |
1,189.1 |
|
|
$ |
2,197.9 |
|
|
$ |
2,979.5 |
|
_____________
(1) Calculated by converting
natural gas to oil equivalent barrels at a ratio of six Mcf of
natural gas to one Boe.
(2) Total proved pre-tax PV 10%
(“Pre-tax PV 10%”) is a supplemental non-GAAP financial measure
that is used by management and external users of our consolidated
financial statements, such as industry analysts, investors, lenders
and rating agencies, and it is derived from the standardized
measure of discounted future net cash flows (the ‘‘Standardized
Measure’’), which is the most directly comparable GAAP financial
measure. Pre-tax PV 10% is computed on the same basis as the
Standardized Measure but without deducting future income taxes. We
believe Pre-tax PV 10% is a useful measure for investors when
evaluating the relative monetary significance of our oil and
natural gas properties. We further believe investors may utilize
our Pre-tax PV 10% as a basis for comparison of the relative size
and value of our proved reserves to other companies because many
factors that are unique to each individual company impact the
amount of future income taxes to be paid. Our management uses this
measure when assessing the potential return on investment related
to our oil and gas properties and acquisitions. However, Pre-tax PV
10% is not a substitute for the Standardized Measure. Our Pre-tax
PV 10% and Standardized Measure do not purport to present the fair
value of our proved oil, NGL and natural gas reserves.
Supplemental Measures
Organic Reserve Replacement
Ratio
The Company uses the organic reserve replacement
ratio as an indicator of the Company’s ability to replace the
reserves that it has developed and to increase its reserves over
time. The ratio is not a representation of value creation and has a
number of limitations that should be considered. For example, the
ratio does not incorporate the costs or timing of developing future
reserves. The organic reserve replacement ratio of 91% is
calculated as (a) our total 2020 proved reserve extensions and
discoveries and revisions to previous estimates of 22.3 MMBoe
divided by (b) the Company’s total 2020 production of 24.6 MMBoe.
The ratio calculation excludes acquisitions and divestitures.
Proved Developed and Drill-Bit Finding
and Development (“F&D”) Costs
The Company uses proved developed F&D cost
and drill-bit F&D cost as indicators of capital efficiency, in
that they measure the Company’s costs to add proved reserves on a
per Boe basis. Both calculations exclude acquisitions and
divestitures and are subject to limitations, including the
uncertainty of future costs to develop the Company’s reserves.
Proved developed F&D of $11.48 per Boe is
calculated as our total 2020 exploration and developments costs
incurred of $302.4 million divided by the sum of (i) total proved
developed reserve extensions and discoveries, (ii) transfers from
proved undeveloped reserves at year-end 2019, and (iii) proved
developed reserve revisions to previous estimates, which altogether
totaled 26.3 MMBoe.
Drill-bit F&D of $13.53 per Boe is
calculated as (a) our total 2020 exploration and developments costs
incurred of $302.4 million divided by (b) the Company’s total 2020
proved reserve extensions and discoveries and revisions to previous
estimates of 22.3 MMBoe.
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