Diamondback Energy, Inc. (NASDAQ: FANG) (“Diamondback” or the
“Company”) today announced financial and operating results for the
fourth quarter and full year ended December 31, 2019.
FOURTH QUARTER 2019
HIGHLIGHTS
- Q4 2019 average production of 195.0
MBO/d (301.3 MBOE/d), with average oil production up 5% over Q3
2019 and 50% over Q4 2018
- Q4 2019 net loss of $(487) million,
which includes a $790 million impairment due to lower SEC commodity
pricing; adjusted net income (as defined and reconciled below) of
$308 million, or $1.93 per diluted share
- Q4 2019 Consolidated Adjusted
EBITDA (as defined and reconciled below) of $869 million; adjusted
EBITDA net of non-controlling interest of $827 million
- Q4 2019 capital expenditures of
$748 million; turned 78 gross operated horizontal wells to
production
- Approved a 100% increase in the
annual cash dividend policy to $1.50 per common share starting
with Q4 2019 payment, subject to discretion of the Board
- Declared Q4 2019 cash dividend of
$0.375 per share payable on March 10, 2020; implies a 2.0%
annualized yield based on the February 14, 2020 share closing price
of $74.97
- Repurchased 2,415,000 shares in Q4
2019 for ~$199 million
- Closed inaugural offering of $3.0
billion of investment grade notes; proceeds used to fully redeem
$1.25 billion of 4.75% notes and pay down a portion of outstanding
credit facility borrowings
- Q4 2019 unhedged realized oil
prices of $54.74/Bbl, representing ~96% of WTI and up 6% versus Q3
2019; expect to realize ~98-101% of WTI in 2020
- Successfully traded majority of
operated New Mexico acreage in the Northern Delaware Basin for
operated Texas acreage in both the Midland and Delaware Basin; less
than 0.1% of current net acreage now on federal land
- Closed previously announced
Drop-Down transaction to subsidiary Viper Energy Partners LP
(NASDAQ: VNOM) ("Viper")
"Diamondback ended 2019 in a position of
strength, achieving 5% sequential oil production growth along with
our highest oil realizations of the year. This, combined with
our industry-leading cost structure, resulted in 18% quarter over
quarter Adjusted EBITDA growth and 31% Adjusted EPS growth in the
quarter. We repurchased 2.4 million shares in the quarter for
approximately $199 million, utilizing free cash flow and a $43
million gain from interest rate swaps unwound as part of our first
investment grade bond offering in November to repurchase shares at
a depressed valuation. Further, Diamondback did not slow
operations in the second half of 2019 and maintained continuous
operations with eight completion crews running consistently through
the end of the year, setting us up for continued growth and
operational momentum in 2020," stated Travis Stice, Chief Executive
Officer of Diamondback.
FULL YEAR 2019 HIGHLIGHTS
- Full year 2019 net income of $240
million, or $1.47 per diluted share; full year 2019 adjusted net
income (as defined and reconciled below) of $1.1 billion, or $6.93
per diluted share
- Full year 2019 consolidated
adjusted EBITDA of $3.1 billion, or $18.71 per diluted share
- Full year 2019 average production
of 187.7 MBO/d (283.0 MBOE/d), an increase of 26% from combined
2018 average daily oil volumes, after adjusting for the full year
2018 impact of the Energen transaction which closed
on November 29, 2018
- Full year 2019 capital expenditures
of $2,921 million; turned 317 operated horizontal wells to
production
- Proved reserves as of December 31,
2019 of 1,128 MMboe (711 MMBo, 63% oil, 67% PDP), up 14% year over
year; proved developed producing ("PDP") reserves of 760 MMboe (457
MMBo, 60% oil), up 18% year over year
- 2019 consolidated proved developed
finding and development ("PD F&D") costs of $10.87/boe; drill
bit finding and development costs of $11.11/boe
- Repurchased 6,385,000 shares for
~$598 million; represents 30% of the Board approved program for up
to $2.0 billion of stock repurchases through December 31, 2020 and
~4% of the Company's float at December 31, 2018
"Looking back, 2019 was a historic year for
Diamondback. We successfully integrated our merger with
Energen Resources, doubling the size of our Company while achieving
greater cost synergies in a shorter period of time than originally
promised at time of deal announcement. We grew pro forma oil
production 26% year over year with a $2.9 billion capital budget,
increased our dividend by 50% and repurchased 6.4 million shares,
or ~4% of our float entering the year. We sold non-core
assets for over $320 million of gross proceeds, dropped down
mineral interests to Viper and took our midstream business public
with approximately $720 million of net proceeds to Diamondback
while retaining 71% post-IPO ownership. In November, we
executed the final piece of our synergy scorecard and refinanced
$3.0 billion of the Company's long-term debt following our upgrade
to investment grade at a weighted average 3.23% interest rate,"
stated Travis Stice, Chief Executive Officer of Diamondback.
Mr. Stice continued, "While we are proud of what
we accomplished in 2019, we do not spend time looking backward at
our tracks in the sand, but rather looking ahead and concentrating
on the future. 2020 has already brought its own industry
challenges, and we are focused on navigating these challenges by
staying disciplined, improving our industry-leading cost structure,
growing production, increasing environmental transparency, and
returning more cash to stockholders as evidenced by our dividend
announcement today. Should commodity prices weaken further or
remain weak for an extended period of time, we will act responsibly
as we have many times in the past and reduce capital
spending. If commodity prices strengthen, we will grow oil
production within our previously announced 2020 budget, and return
cash to stockholders or pay down debt.”
ENVIRONMENTAL, SOCIAL, GOVERNANCE AND
COMPENSATION: RECENT AND EXPECTED CHANGES
Additionally, Diamondback today announced recent
and planned changes regarding environmental, social and governance
("ESG") disclosure and performance, as well as approved and
expected changes to its compensation program. The Company
plans to provide additional detail for these and other changes in
its upcoming proxy, which it expects to file in the second quarter
of 2020.
- Formed Safety, Sustainability and
Corporate Responsibility Committee of the Board of Directors in the
fourth quarter of 2019 with the goal to become best in class in
terms of both disclosure and performance as it relates to
sustainable long term development of our natural resources
- Adopted Proxy Access in the fourth
quarter of 2019
- Plan to add an absolute total
shareholder return ("TSR") modifier to long term incentive (“LTI”)
compensation that reduces payouts upon negative performance period
TSR, pays at target upon achieving a performance period annual TSR
of 0-15%, and has a multiplier upon achieving a performance period
annual TSR of greater than 15%
- Plan to replace executive
employment agreements with a severance and change of control plan
consistent with current market practice
- Plan to update annual short-term
incentive ("STI") metrics to include an ESG component with expected
weighting of 10-15%
- ESG component expected to be
determined by meeting or exceeding key environmental and safety
metrics including, but not limited to: flaring, GHG emissions,
recycled water, fluid spill control and Total Recordable Incident
Rate (safety); each metric will be measured and compensation will
be tied to the metrics presented, without discretion
- Existing metrics expected to remain
unchanged (return on average capital employed, per lateral foot
well costs and per boe PD F&D costs, LOE and Cash G&A
expense)
“Diamondback has steadily made changes to
compensation and governance practices as the Company has grown and
the market has evolved. The Company was one of the first in
our industry to remove all growth metrics from its scorecard five
years ago, replacing those metrics with cost control and capital
efficiency metrics while also adding return on average capital
employed in 2018. The Company is taking the next step forward
in 2020 by adding tangible environmental and safety targets to the
scorecard. One unique aspect of Diamondback's annual cash
incentive program is that while 100 percent of senior management’s
cash incentive compensation is tied to the scorecard, up to half of
each employee’s discretionary cash incentive compensation is also
tied to the same scorecard, creating alignment throughout the
organization. Diamondback is committed to being both best in
class in terms of disclosure, but more importantly performance,
when it comes to sustainable development of our natural resources
in West Texas, where we are headquartered and operate,” stated
Steve West, Chairman of the Board of Directors of Diamondback.
OPERATIONS UPDATE
Diamondback’s Q4 2019 production averaged 301.3
MBOE/d (195.0 MBO/d), up 5% quarter over quarter from 287.1 MBOE/d
in Q3 2019, and up 65% year over year from 182.8 MBOE/d in Q4
2018.
During the fourth quarter of 2019, Diamondback
drilled 76 gross horizontal wells and turned 78 operated horizontal
wells to production. The average lateral length for the wells
completed during the fourth quarter was 9,393 feet. Operated
completions during the fourth quarter consisted of 37 Wolfcamp A
wells, 21 Lower Spraberry wells, eight Wolfcamp B wells, six Third
Bone Spring wells, two Second Bone Spring wells, two Jo Mill wells,
one Middle Spraberry well and one Wolfcamp D well.
For the full year ended December 31, 2019, the
Company drilled 331 gross horizontal wells and turned 317 operated
horizontal wells to production. The average lateral length for
wells completed during the full year 2019 was 9,598 feet, and
consisted of 179 Wolfcamp A wells, 64 Lower Spraberry wells, 33
Wolfcamp B wells, 11 Third Bone Spring wells, 10 Middle Spraberry
wells, nine Second Bone Spring wells, eight Jo Mill wells, two
Wolfcamp D wells and one Meramec well.
Diamondback recently began initial appraisal of
its Limelight exploration acreage in Southeast Ector and Northeast
Crane counties, completing its first well targeting the Meramec
with a 4,720 foot lateral. This well, the Xanadu 31 1H,
commenced with an average 30-day 2-stream initial production ("IP")
rate of 104 boe/d per 1,000 feet (83% oil) and went on to achieve
an average 90-day rate of 76 boe/d per 1,000 feet (82% oil).
In the Midland Basin, Diamondback continues to
have success in the Middle Spraberry and Jo Mill intervals.
The Company recently completed a three well pad in Midland County
with an average lateral length of 9,253 feet. These wells
commenced with an average peak 30-day IP rate of 113 boe/d per
1,000 feet (83% oil).
In the Delaware Basin, the Company continues to
be encouraged by operated completions targeting the Second Bone
Spring. Most recently, Diamondback completed the SNL 27-25
UNIT 4BS well with a 7,554 lateral in Pecos County, which achieved
a peak 30-day IP rate of 154 boe/d per 1,000 feet (89% oil).
FINANCIAL UPDATE
Diamondback's fourth quarter 2019 net loss was
$(487) million, or $(3.04) per diluted share. Adjusted net
income (a non-GAAP financial measure as defined and reconciled
below) was $308 million, or $1.93 per diluted share, up 31% from
$1.47 in Q3 2019 and up 60% from $1.21 in Q4 2018.
Fourth quarter 2019 Adjusted EBITDA net of
non-controlling interest (as defined and reconciled below) was $827
million, up 18% from $699 million in Q3 2019 and up 82% from $455
million in Q4 2018.
Fourth quarter 2019 average realized prices were
$54.74 per barrel of oil, $1.07 per Mcf of natural gas and $15.15
per barrel of natural gas liquids, resulting in a total equivalent
unhedged price of $39.28/BOE. As previously indicated,
Diamondback expects realized prices to improve relative to WTI
through the remainder of 2020 as out of market fixed differential
contracts have now rolled off and converted to Diamondback's
commitments on the EPIC and Gray Oak pipelines or the current
Midland market price. Based on current market differentials
and estimated in-basin gathering costs, Diamondback expects to
realize ~98-101% of WTI in 2020, all including the effect of
current basis hedges, firm transportation agreements and in-basin
gathering costs.
Diamondback's cash operating costs for the
fourth quarter of 2019 were $8.77 per BOE, including lease
operating expenses ("LOE") of $4.52 per BOE, cash general and
administrative ("G&A") expenses of $0.54 per BOE and production
and ad valorem taxes and gathering and transportation of $3.71 per
BOE.
In December 2019, Diamondback completed an
offering of $3.0 billion aggregate principal amount of investment
grade notes, comprised of $1.0 billion of 2.875% senior notes due
2024, $800 million of 3.250% senior notes due 2026 and $1.2 billion
of 3.500% senior notes due 2029. Net proceeds from these
transactions were used to repay a portion of the outstanding
borrowings under its credit facility, and to fully redeem $1.25
billion aggregate principal amount of its 4.750% senior notes at an
aggregate purchase price of approximately $1.3 billion.
As of December 31, 2019, Diamondback had
$109 million in standalone cash and approximately $13 million of
outstanding borrowings under its revolving credit facility.
During the fourth quarter of 2019, Diamondback
spent $652 million on drilling and completion, $23 million on
non-operated properties, $15 million on infrastructure and $58
million on midstream, for total capital expenditures of $748
million. For the year ended December 31, 2019, the Company
spent $2,452 million on drilling and completion, $105 million on
non-operated properties, $120 million on infrastructure and $244
million on midstream, for total capital expenditures of $2,921
million.
CAPITAL RETURN PROGRAM
Diamondback announced today that the Company's
Board of Directors declared a cash dividend of $0.375 per common
share for the fourth quarter of 2019 payable on March 10, 2020, to
stockholders of record at the close of business on March 3,
2020.
During the fourth quarter of 2019, Diamondback
repurchased 2,415,000 shares of common stock for approximately $199
million. For the full year 2019, Diamondback repurchased
6,385,000 shares, or approximately 30% of the Board approved
program.
The repurchase program is authorized to extend
through December 31, 2020, and the Company intends to purchase
stock under the repurchase program opportunistically with funds
from cash generated from operations and liquidity events such as
the sale of assets. This repurchase program may be suspended
from time to time, modified, extended or discontinued by the Board
of Directors at any time. Purchases under the repurchase
program may be made from time to time in open market or privately
negotiated transactions in compliance with Rule 10b-18 under the
Securities Exchange Act of 1934, as amended, and will be subject to
market conditions, applicable legal requirements, contractual
obligations and other factors. Any stock purchased as part of
this program will be retired and made available for future
issuances by the Company.
RESERVES
Ryder Scott Company, L.P. prepared estimates of
Diamondback's proved reserves as of December 31, 2019.
Reference prices of $55.69 per barrel of oil and $2.58 per MMbtu of
natural gas were used in accordance with applicable rules of the
Securities and Exchange Commission. Realized prices with applicable
differentials were $51.88 per barrel of oil, $0.18 per Mcf of
natural gas and $15.65 per barrel of natural gas liquids.
Proved reserves at year-end 2019 of 1,128 MMboe
represent a 14% increase over year-end 2018 reserves. Proved
developed reserves increased by 18% to 760 MMboe (67% of
total proved reserves) as of December 31, 2019, reflecting the
continued development of the Company's horizontal well inventory.
Proved undeveloped reserves ("PUD" or "PUDs") increased to 368
MMboe, a 6% increase over year-end 2018, and are comprised of 499
locations, 97 which are in the Delaware Basin. Crude oil
represents 63% of Diamondback's total proved reserves.
Net proved reserve additions of 239 MMboe
resulted in a reserve replacement ratio of 231% (defined as the sum
of extensions, discoveries, revisions and purchases, divided by
annual production). The organic reserve replacement ratio was
250% (defined as the sum of extensions, discoveries and revisions,
divided by annual production).
Extensions and discoveries of reserves were the
primary contributor to the increase in reserves totaling 376 MMboe
followed by net purchases of reserves totaling 21 MMboe, with
divestitures of 41 MMboe and downward revisions of 118
MMboe. PDP extensions accounted for 41% of the total increase
in reserves. PDP extensions were the result of 283 wells in which
the Company has a working interest, and PUD extensions were the
result of 291 new locations in which the Company has a working
interest. Net divestitures of reserves of 20 MMboe were the
net result of acquisitions of 21 MMboe and divestitures of 41 MMboe
primarily associated with the sale of the Company's conventional
Central Basin Platform assets. Downward revisions of 118 MMboe
were the result of negative revisions due to lower product pricing
of 42 MMboe and PUD downgrades of 70 MMboe primarily from changes
in the corporate development plan and inventory optimization. These
revisions were partially offset by positive performance revisions
of 10 MMboe from increased NGL recoveries.
88% of the PUD downgrades, or 61 MMboe, are
related to the reclassification of PUDs to non-proved categories
that do not fit in the Company's current three year development
plan due to inventory optimization and high grading after the
Energen and Diamondback merger. The SEC PUD guidelines allow a
company to book PUD reserves associated with projects that are to
occur within the next five years, but Diamondback takes a more
conservative approach to the booking of PUD reserves by choosing to
book minimal PUD reserves outside of its three year development
plan. The benefit of booking PUDs has decreased as the Company has
grown and no longer has a reserve-based revolving credit facility
after earning investment grade status in late 2019. With its
current development plan, the Company expects to continue its
strong PUD conversion ratio in 2020 by converting an estimated 35%
of its PUDs to a Proved Developed category, and develop ~66% of the
consolidated 2019 year-end PUD reserves by the end of 2021.
|
|
|
|
|
|
Oil (MBbls) |
Liquids (MBbls) |
Gas (MMcf) |
MBOE |
Proved Reserves As of December
31, 2018 |
626,936 |
|
190,291 |
|
1,048,649 |
|
992,001 |
|
Extensions and discoveries |
256,569 |
|
66,572 |
|
318,874 |
|
376,288 |
|
Revisions of previous estimates |
(84,789 |
) |
(8,166 |
) |
(149,657 |
) |
(117,898 |
) |
Purchase of reserves in place |
13,974 |
|
3,813 |
|
19,830 |
|
21,092 |
|
Divestitures |
(33,269 |
) |
(3,809 |
) |
(21,272 |
) |
(40,623 |
) |
Production |
(68,518 |
) |
(18,498 |
) |
(97,613 |
) |
(103,285 |
) |
Proved Reserves As of December
31, 2019 |
710,903 |
|
230,203 |
|
1,118,811 |
|
1,127,575 |
|
|
|
|
|
|
|
|
|
|
Diamondback's exploration and development costs
in 2019 were $2,871 million. PD F&D costs were
$10.87/boe. PD F&D costs are defined as exploration and
development costs, excluding midstream, divided by the sum of
reserves associated with transfers from proved undeveloped reserves
at year-end 2018 including any associated revisions in 2019 and
extensions and discoveries placed on production during 2018. Drill
bit F&D costs were $11.11/boe including the effects of all
revisions including pricing revisions. Drill bit F&D costs are
defined as the exploration and development costs, excluding
midstream, divided by the sum of extensions, discoveries and
revisions. Diamondback's approach to PUD reserve booking negatively
impacted drill bit F&D in 2019. If Diamondback's PUD to PDP
ratio had remained constant compared to 2018 along with constant
year over year product pricing, the Company estimates its drill bit
F&D would have been ~$2.50/boe less in 2019.
|
|
|
|
Year Ended December 31, |
|
|
2019 |
|
2018 |
|
2017 |
|
(In millions) |
Acquisition costs: |
|
|
|
|
|
Proved properties |
$ |
194 |
|
|
$ |
5,665 |
|
|
$ |
455 |
|
Unproved properties |
418 |
|
|
5,818 |
|
|
2,692 |
|
Development costs |
956 |
|
|
493 |
|
|
145 |
|
Exploration costs |
1,915 |
|
|
1,090 |
|
|
780 |
|
Total |
$ |
3,483 |
|
|
$ |
13,066 |
|
|
$ |
4,072 |
|
|
|
|
|
|
|
|
|
|
|
|
|
UPDATED 2020 GUIDANCE
Below is Diamondback's guidance for the full year 2020, which is
unchanged from the production, activity and capital budget guidance
released in November 2019, and has been updated to reflect unit
cost expectations.
Note the 2020 capital program includes 100%
working interest capital for 15 - 17 wells on the San Pedro joint
venture acreage with Carlyle due to the accounting treatment of the
joint venture, resulting in over $175 million of gross capital for
these projects in the consolidated budget. Per the joint
development agreement, Diamondback's net capital contribution to
these wells will be less than 20% of the total capital ($35
million). The majority of the working interest associated
with this development reverts back to Diamondback should certain
return thresholds be met.
|
|
|
|
2020 Guidance |
2020 Guidance |
|
Diamondback Energy, Inc. |
Viper Energy Partners LP |
|
|
|
Total net production –
MBOE/d |
310.0 - 325.0 |
27.0 - 30.0 |
Oil production – MBO/d |
205.0 - 215.0 |
17.0 - 19.0 |
|
|
|
Unit costs ($/BOE) |
|
|
Lease operating expenses,
including workovers |
$4.40 - $4.80 |
|
Gathering and
transportation |
$0.90 - $1.10 (Q1 $1.15 - $1.35) |
|
G&A |
|
|
Cash G&A |
$0.70 - $0.90 |
Under $0.80 |
Non-cash equity-based compensation |
$0.40 - $0.65 |
Under $0.25 |
D,D&A |
$13.00 - $15.00 |
$10.50 - $12.50 |
Interest expense (net of
interest income) |
$1.25 - $1.75 |
$2.75 - $3.25 |
|
|
|
Production and ad valorem
taxes (% of revenue)(a) |
7.0% |
7.0% |
Corporate tax rate (% of
pre-tax income) |
23% |
|
|
|
|
Gross horizontal D,C&E/Ft.
- Midland Basin |
$720 - $750 |
|
Gross horizontal D,C&E/Ft.
- Delaware Basin |
$1,075 - $1,125 |
|
Gross horizontal wells
completed (net) |
320 - 360 (288 - 324) |
|
Average lateral length
(Ft.) |
~9,700' |
|
Midland Basin net lateral feet
(%) |
~55% |
|
Delaware Basin net lateral
feet (%) |
~45% |
|
|
|
|
Capital Budget ($ -
million) |
|
|
Horizontal drilling and
completion |
$2,450 - $2,600 |
|
Midstream (ex. long-haul
pipeline investments) |
$200 - $225 |
|
Infrastructure |
$150 - $175 |
|
2020 Capital Spend |
$2,800 - $3,000 |
|
(a) Includes production taxes of 4.6% for
crude oil and 7.5% for natural gas and NGLs and ad valorem
taxes. |
|
CONFERENCE CALL
Diamondback will host a conference call and
webcast for investors and analysts to discuss its results for the
fourth quarter of 2019 on Wednesday, February 19,
2020 at 9:00 a.m. CT. Participants should call (877)
440-7573 (United States/Canada) or (253) 237-1144 (International)
and use the confirmation code 2383801. A telephonic replay will be
available from 12:00 p.m. CT on Wednesday, February
19, 2020 through Wednesday, February 26,
2020 at 12:00 p.m. CT. To access the replay, call (855)
859-2056 (United States/Canada) or (404) 537-3406 (International)
and enter confirmation code 2383801. A live broadcast of the
earnings conference call will also be available via the internet
at www.diamondbackenergy.com under the “Investor
Relations” section of the site. A replay will also be available on
the website following the call.
About Diamondback Energy, Inc.
Diamondback is an independent oil and natural
gas company headquartered in Midland, Texas focused on the
acquisition, development, exploration and exploitation of
unconventional, onshore oil and natural gas reserves in the Permian
Basin in West Texas. For more information, please visit
www.diamondbackenergy.com.
Forward Looking Statements
This news release contains forward-looking
statements within the meaning of the Private Securities Litigation
Reform Act of 1995. All statements, other than historical
facts, that address activities that Diamondback assumes, plans,
expects, believes, intends or anticipates (and other similar
expressions) will, should or may occur in the future are
forward-looking statements. The forward-looking statements
are based on management’s current beliefs, based on currently
available information, as to the outcome and timing of future
events, including acquisitions and sales of assets, future
dividends, production, drilling and capital expenditure plans and
effects of hedging arrangements. These forward-looking
statements involve certain risks and uncertainties that could cause
the results to differ materially from those expected by the
management of Diamondback. Information concerning these risks
and other factors can be found in Diamondback’s filings with the
Securities and Exchange Commission, including its Forms 10-K, 10-Q
and 8-K, which can be obtained free of charge on the Securities and
Exchange Commission’s web site at http://www.sec.gov. Diamondback
undertakes no obligation to update or revise any forward-looking
statement.
|
Diamondback Energy, Inc. |
Consolidated Balance Sheets |
(unaudited, in millions, except share
amounts) |
|
|
|
|
December 31, |
December 31, |
|
2019 |
2018 |
Assets |
|
|
Current
assets: |
|
|
Cash and cash equivalents |
$ |
123 |
|
$ |
215 |
|
Restricted cash |
5 |
|
— |
|
Accounts receivable: |
|
|
Joint interest and other, net |
186 |
|
96 |
|
Oil and natural gas sales |
429 |
|
296 |
|
Inventories |
37 |
|
37 |
|
Derivative instruments |
46 |
|
231 |
|
Prepaid expenses and other |
43 |
|
50 |
|
Total current assets |
869 |
|
925 |
|
Property and
equipment: |
|
|
Oil and natural gas properties, full cost method of accounting
($9,207 million and $9,670 million excluded from amortization at
December 31, 2019 and 2018, respectively) |
25,782 |
|
22,299 |
|
Midstream assets |
931 |
|
700 |
|
Other property, equipment and land |
125 |
|
147 |
|
Accumulated depletion, depreciation, amortization and
impairment |
(5,003 |
) |
(2,774 |
) |
Net property and equipment |
21,835 |
|
20,372 |
|
Equity method
investments |
479 |
|
1 |
|
Derivative
instruments |
7 |
|
— |
|
Deferred tax
asset |
142 |
|
97 |
|
Investment in real
estate, net |
109 |
|
116 |
|
Other assets |
90 |
|
85 |
|
Total assets |
$ |
23,531 |
|
$ |
21,596 |
|
Liabilities and Stockholders’ Equity |
|
|
Current
liabilities: |
|
|
Accounts payable-trade |
$ |
179 |
|
$ |
128 |
|
Accrued capital expenditures |
475 |
|
495 |
|
Other accrued liabilities |
304 |
|
253 |
|
Revenues and royalties payable |
278 |
|
143 |
|
Derivative instruments |
27 |
|
— |
|
Total current liabilities |
1,263 |
|
1,019 |
|
Long-term
debt |
5,371 |
|
4,464 |
|
Derivative
instruments |
— |
|
15 |
|
Asset retirement
obligations |
94 |
|
136 |
|
Deferred income
taxes |
1,886 |
|
1,785 |
|
Other long-term
liabilities |
11 |
|
10 |
|
Total liabilities |
8,625 |
|
7,429 |
|
Commitments and
contingencies |
|
|
Stockholders’
equity: |
|
|
Common stock, $0.01 par value, 200,000,000 shares authorized,
159,034,734 issued and outstanding at December 31, 2019;
200,000,000 shares authorized, 164,273,447 issued and outstanding
at December 31, 2018 |
2 |
|
2 |
|
Additional paid-in capital |
12,357 |
|
12,936 |
|
Retained earnings |
890 |
|
762 |
|
Total Diamondback Energy, Inc. stockholders’ equity |
13,249 |
|
13,700 |
|
Non-controlling
interest |
1,657 |
|
467 |
|
Total equity |
14,906 |
|
14,167 |
|
Total liabilities and equity |
$ |
23,531 |
|
$ |
21,596 |
|
|
|
|
|
|
|
|
|
Diamondback Energy, Inc. |
Consolidated Statements of Operations |
(unaudited, $ in millions except per share data, shares in
thousands) |
|
|
|
|
|
|
|
|
|
Three Months EndedDecember 31, |
|
Year Ended December 31, |
|
2019 |
|
2018 |
|
2019 |
|
2018 |
Revenues: |
Oil, natural gas and natural gas liquid sales |
$ |
1,089 |
|
|
$ |
623 |
|
|
$ |
3,887 |
|
|
$ |
2,130 |
|
Lease bonus |
— |
|
|
1 |
|
|
4 |
|
|
3 |
|
Midstream services |
13 |
|
|
7 |
|
|
64 |
|
|
34 |
|
Other operating income |
2 |
|
|
2 |
|
|
9 |
|
|
9 |
|
Total revenues |
1,104 |
|
|
633 |
|
|
3,964 |
|
|
2,176 |
|
Costs and
expenses: |
|
|
|
|
|
|
|
Lease operating expenses |
126 |
|
|
76 |
|
|
490 |
|
|
205 |
|
Production and ad valorem taxes |
68 |
|
|
40 |
|
|
248 |
|
|
133 |
|
Gathering and transportation |
34 |
|
|
9 |
|
|
88 |
|
|
26 |
|
Midstream services |
31 |
|
|
23 |
|
|
91 |
|
|
72 |
|
Depreciation, depletion and amortization |
401 |
|
|
232 |
|
|
1,447 |
|
|
623 |
|
Impairment of oil and natural gas properties |
790 |
|
|
— |
|
|
790 |
|
|
— |
|
General and administrative expenses |
36 |
|
|
20 |
|
|
104 |
|
|
65 |
|
Asset retirement obligation accretion |
1 |
|
|
1 |
|
|
7 |
|
|
2 |
|
Merger and integration expense |
— |
|
|
36 |
|
|
— |
|
|
36 |
|
Other operating expense |
1 |
|
|
1 |
|
|
4 |
|
|
3 |
|
Total costs and expenses |
1,488 |
|
|
438 |
|
|
3,269 |
|
|
1,165 |
|
Income (loss) from operations |
(384 |
) |
|
195 |
|
|
695 |
|
|
1,011 |
|
Other
income (expense): |
|
|
|
|
|
|
|
Interest expense, net |
(39 |
) |
|
(38 |
) |
|
(172 |
) |
|
(87 |
) |
Other (expense) income, net |
(7 |
) |
|
— |
|
|
(2 |
) |
|
89 |
|
(Loss) gain on derivative instruments, net |
(111 |
) |
|
240 |
|
|
(108 |
) |
|
101 |
|
Gain (loss) on revaluation of investment |
1 |
|
|
(6 |
) |
|
5 |
|
|
(1 |
) |
Loss on extinguishment of debt |
(56 |
) |
|
— |
|
|
(56 |
) |
|
— |
|
Total other
(expense) income, net |
(212 |
) |
|
196 |
|
|
(333 |
) |
|
102 |
|
Income
(loss) before income taxes |
(596 |
) |
|
391 |
|
|
362 |
|
|
1,113 |
|
(Benefit from)
provision for income taxes |
(124 |
) |
|
85 |
|
|
47 |
|
|
168 |
|
Net
income (loss) |
(472 |
) |
|
306 |
|
|
315 |
|
|
945 |
|
Net income (loss)
attributable to non-controlling interest |
15 |
|
|
(1 |
) |
|
75 |
|
|
99 |
|
Net
income (loss) attributable to Diamondback Energy,
Inc. |
$ |
(487 |
) |
|
$ |
307 |
|
|
$ |
240 |
|
|
$ |
846 |
|
|
|
|
|
|
|
|
|
Earnings
per common share: |
|
|
|
|
|
|
|
Basic |
$ |
(3.04 |
) |
|
$ |
2.50 |
|
|
$ |
1.47 |
|
|
$ |
8.09 |
|
Diluted |
$ |
(3.04 |
) |
|
$ |
2.50 |
|
|
$ |
1.47 |
|
|
$ |
8.06 |
|
Weighted
average common shares outstanding: |
|
|
|
|
|
|
|
Basic |
159,998 |
|
122,510 |
|
163,493 |
|
104,622 |
Diluted |
160,154 |
|
122,739 |
|
163,843 |
|
104,929 |
Dividends
declared per share |
$ |
0.3750 |
|
$ |
0.1250 |
|
$ |
0.9375 |
|
$ |
0.5000 |
|
|
|
|
|
|
|
|
|
Diamondback Energy, Inc. |
Consolidated Statements of Cash Flows |
(unaudited, in millions) |
|
|
|
|
Year Ended December 31, |
|
2019 |
2018 |
Cash flows from
operating activities: |
|
|
Net income |
$ |
315 |
|
$ |
945 |
|
Adjustments to reconcile net income to net cash provided by
operating activities: |
|
|
Provision for deferred income taxes |
47 |
|
168 |
|
Impairment of oil and natural gas properties |
790 |
|
— |
|
Asset retirement obligation accretion |
7 |
|
2 |
|
Depreciation, depletion and amortization |
1,447 |
|
623 |
|
Amortization of debt issuance costs |
9 |
|
12 |
|
Loss on early extinguishment of debt |
56 |
|
— |
|
Change in fair value of derivative instruments |
188 |
|
(222 |
) |
Loss from equity investment |
6 |
|
— |
|
(Gain) loss on revaluation of investment |
(5 |
) |
1 |
|
Equity-based compensation expense |
48 |
|
27 |
|
(Gain) loss on sale of assets, net |
(1 |
) |
3 |
|
(Gain) loss on sale of inventory |
(1 |
) |
— |
|
Restricted cash |
(5 |
) |
— |
|
Changes in operating assets and liabilities: |
|
|
Accounts receivable |
(187 |
) |
13 |
|
Inventories |
(10 |
) |
(14 |
) |
Prepaid expenses and other |
29 |
|
25 |
|
Accounts payable and accrued liabilities |
(129 |
) |
(7 |
) |
Income tax payable |
— |
|
(1 |
) |
Accrued interest |
(5 |
) |
(22 |
) |
Revenues and royalties payable |
135 |
|
12 |
|
Net cash provided
by operating activities |
2,734 |
|
1,565 |
|
Cash flows from
investing activities: |
|
|
Drilling, completions and non-operated additions to oil and natural
gas properties |
(2,557 |
) |
(1,359 |
) |
Infrastructure additions to oil and natural gas properties |
(120 |
) |
(102 |
) |
Additions to midstream assets |
(244 |
) |
(204 |
) |
Purchase of other property, equipment and land |
(5 |
) |
(7 |
) |
Acquisition of leasehold interests |
(443 |
) |
(1,371 |
) |
Acquisition of mineral interests |
(333 |
) |
(440 |
) |
Proceeds from sale of assets |
300 |
|
80 |
|
Investment in real estate |
(1 |
) |
(111 |
) |
Funds held in escrow |
— |
|
11 |
|
Equity investments |
(485 |
) |
— |
|
Net cash used in
investing activities |
(3,888 |
) |
(3,503 |
) |
Cash flows from
financing activities: |
|
|
Proceeds from borrowings under credit facility |
2,350 |
|
2,652 |
|
Repayment under credit facility |
(3,718 |
) |
(1,242 |
) |
Repayment on Energen's credit facility |
— |
|
(559 |
) |
Proceeds from senior notes |
3,469 |
|
1,062 |
|
Repayment of senior notes |
(1,250 |
) |
— |
|
Premium on extinguishment of debt |
(44 |
) |
— |
|
Proceeds from joint venture |
39 |
|
— |
|
Debt issuance costs |
(18 |
) |
(25 |
) |
Public offering costs |
(41 |
) |
(3 |
) |
Proceeds from public offerings |
1,106 |
|
305 |
|
Proceeds from exercise of stock options |
9 |
|
— |
|
Repurchased shares for tax withholdings |
(13 |
) |
(14 |
) |
Repurchased as part of share buyback |
(593 |
) |
— |
|
Dividends to stockholders |
(112 |
) |
(37 |
) |
Distributions to non-controlling interest |
(122 |
) |
(98 |
) |
Net cash provided
by financing activities |
1,062 |
|
2,041 |
|
Net (decrease)
increase in cash and cash equivalents |
(92 |
) |
103 |
|
Cash and cash
equivalents at beginning of period |
215 |
|
112 |
|
Cash and cash
equivalents at end of period |
$ |
123 |
|
$ |
215 |
|
|
|
|
Supplemental disclosure of cash flow
information: |
|
|
Interest paid, net of capitalized interest |
$ |
237 |
|
$ |
114 |
|
Cash paid for income taxes |
$ |
— |
|
$ |
1 |
|
Supplemental disclosure of non-cash
transactions: |
|
|
Change in accrued capital expenditures |
$ |
(20 |
) |
$ |
274 |
|
Capitalized stock-based compensation |
$ |
17 |
|
$ |
10 |
|
Common stock issued for Ajax |
$ |
— |
|
$ |
340 |
|
Common stock issued for business combination(1) |
$ |
— |
|
$ |
7,136 |
|
Asset retirement obligations acquired |
$ |
4 |
|
$ |
111 |
|
(1) Includes
$7 billion of Common stock issued for business combination, $14
million for stock options assumed and $52 million for restricted
stock units assumed. |
|
Diamondback Energy, Inc. |
Selected Operating Data |
(unaudited) |
|
|
|
|
|
|
|
|
|
Three Months Ended December 31, |
|
Year Ended December 31, |
|
2019 |
|
2018 |
|
2019 |
|
2018 |
Production Data: |
Oil (MBbls) |
17,937 |
|
|
11,968 |
|
|
68,518 |
|
|
34,367 |
|
Natural gas (MMcf) |
28,219 |
|
|
12,952 |
|
|
97,613 |
|
|
34,669 |
|
Natural gas liquids (MBbls) |
5,078 |
|
|
2,689 |
|
|
18,498 |
|
|
7,465 |
|
Combined volumes (MBOE)(1)(2) |
27,718 |
|
|
16,816 |
|
|
103,285 |
|
|
47,610 |
|
|
|
|
|
|
|
|
|
Daily oil volumes (BO/d) |
194,972 |
|
|
130,091 |
|
|
187,721 |
|
|
94,156 |
|
Daily combined volumes (BOE/d)(2) |
301,284 |
|
|
182,785 |
|
|
282,972 |
|
|
130,439 |
|
|
|
|
|
|
|
|
|
Average
Prices: |
|
|
|
|
|
|
|
Oil ($ per Bbl) |
$ |
54.74 |
|
|
$ |
45.51 |
|
|
$ |
51.87 |
|
|
$ |
54.66 |
|
Natural gas ($ per Mcf) |
$ |
1.07 |
|
|
$ |
1.62 |
|
|
$ |
0.68 |
|
|
$ |
1.76 |
|
Natural gas liquids ($ per Bbl) |
$ |
15.15 |
|
|
$ |
21.10 |
|
|
$ |
14.42 |
|
|
$ |
25.47 |
|
Combined ($ per BOE) |
$ |
39.28 |
|
|
$ |
37.01 |
|
|
$ |
37.63 |
|
|
$ |
44.73 |
|
Oil, hedged ($ per Bbl)(3) |
$ |
54.69 |
|
|
$ |
45.31 |
|
|
$ |
51.96 |
|
|
$ |
51.20 |
|
Natural gas, hedged ($ per MMbtu)(3) |
$ |
1.15 |
|
|
$ |
1.44 |
|
|
$ |
0.86 |
|
|
$ |
1.72 |
|
Natural gas liquids, hedged ($ per Bbl)(1) |
$ |
15.93 |
|
|
$ |
21.09 |
|
|
$ |
15.20 |
|
|
$ |
25.46 |
|
Average price, hedged ($ per BOE)(3) |
$ |
39.48 |
|
|
$ |
36.72 |
|
|
$ |
38.00 |
|
|
$ |
42.20 |
|
|
|
|
|
|
|
|
|
Average
Costs per BOE: |
|
|
|
|
|
|
|
Lease operating expense |
$ |
4.52 |
|
|
$ |
4.51 |
|
|
$ |
4.74 |
|
|
$ |
4.31 |
|
Production and ad valorem taxes |
2.46 |
|
|
2.36 |
|
|
2.40 |
|
|
2.79 |
|
Gathering and transportation expense |
1.25 |
|
|
0.56 |
|
|
0.86 |
|
|
0.55 |
|
General and administrative - cash component |
0.54 |
|
|
0.67 |
|
|
0.54 |
|
|
0.79 |
|
Total operating expense - cash |
$ |
8.77 |
|
|
$ |
8.10 |
|
|
$ |
8.54 |
|
|
$ |
8.44 |
|
|
|
|
|
|
|
|
|
General and administrative - non-cash component |
$ |
0.73 |
|
|
$ |
0.49 |
|
|
$ |
0.46 |
|
|
$ |
0.57 |
|
Depreciation, depletion and amortization |
$ |
14.48 |
|
|
$ |
13.77 |
|
|
$ |
14.01 |
|
|
$ |
13.09 |
|
Interest expense, net |
$ |
1.40 |
|
|
$ |
2.26 |
|
|
$ |
1.66 |
|
|
$ |
1.83 |
|
Merger and integration expense |
$ |
— |
|
|
$ |
2.19 |
|
|
$ |
— |
|
|
$ |
0.77 |
|
(1) Bbl equivalents are calculated using a conversion rate of
six Mcf per one Bbl. |
(2) The volumes presented are based on actual results and are
not calculated using the rounded numbers in the table above. |
(3) Hedged prices reflect the effect of our commodity
derivative transactions on our average sales prices. Our
calculation of such effects includes realized gains and losses on
cash settlements for commodity derivatives, which we do not
designate for hedge accounting. |
|
NON-GAAP FINANCIAL MEASURES
Adjusted EBITDA is a supplemental non-GAAP
financial measure that is used by management and external users of
our financial statements, such as industry analysts, investors,
lenders and rating agencies. The Company defines Adjusted EBITDA as
net income plus non-cash (gain) loss on derivative instruments,
net, interest expense, net, depreciation, depletion and
amortization, impairment expense, non-cash equity-based
compensation expense, capitalized equity-based compensation
expense, asset retirement obligation accretion expense, loss on
extinguishment of debt, (gain) loss on revaluation of investment,
merger and integration expense and income tax (benefit) provision.
Adjusted EBITDA is not a measure of net income as determined by
United States’ generally accepted accounting principles ("GAAP").
Management believes Adjusted EBITDA is useful because it allows it
to more effectively evaluate the Company’s operating performance
and compare the results of its operations from period to period
without regard to its financing methods or capital structure. The
Company adds the items listed above to net income in arriving at
Adjusted EBITDA because these amounts can vary substantially from
company to company within its industry depending upon accounting
methods and book values of assets, capital structures and the
method by which the assets were acquired. Adjusted EBITDA 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 the Company’s operating performance or liquidity. Certain items
excluded from Adjusted EBITDA 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 EBITDA. The Company’s computation of Adjusted EBITDA
may not be comparable to other similarly titled measures of other
companies or to such measure in our credit facility or any of our
other contracts.
The following tables present a reconciliation of
the non-GAAP financial measure of Adjusted EBITDA to the GAAP
financial measure of net income.
|
Diamondback
Energy, Inc. |
Reconciliation of Adjusted EBITDA to Net
Income |
(unaudited,
in millions) |
|
|
|
|
|
|
|
|
|
Three Months Ended December 31, |
|
Year Ended December 31, |
|
2019 |
|
2018 |
|
2019 |
|
2018 |
Net income (loss) |
$ |
(472 |
) |
|
$ |
306 |
|
|
$ |
315 |
|
|
$ |
945 |
|
Non-cash loss (gain) on derivative instruments,
net |
158 |
|
|
(246 |
) |
|
188 |
|
|
(222 |
) |
Interest expense, net |
39 |
|
|
38 |
|
|
172 |
|
|
87 |
|
Depreciation, depletion and amortization |
401 |
|
|
232 |
|
|
1,447 |
|
|
623 |
|
Impairment of oil and natural gas properties |
790 |
|
|
— |
|
|
790 |
|
|
— |
|
Non-cash equity-based compensation expense |
29 |
|
|
11 |
|
|
65 |
|
|
37 |
|
Capitalized equity-based compensation expense |
(8 |
) |
|
(3 |
) |
|
(17 |
) |
|
(10 |
) |
Asset retirement obligation accretion expense |
1 |
|
|
1 |
|
|
7 |
|
|
2 |
|
Loss on extinguishment of debt |
56 |
|
|
— |
|
|
56 |
|
|
— |
|
Loss (gain) on revaluation of investment |
(1 |
) |
|
6 |
|
|
(5 |
) |
|
1 |
|
Merger and integration expense |
— |
|
|
36 |
|
|
— |
|
|
36 |
|
Income tax (benefit) provision |
(124 |
) |
|
85 |
|
|
47 |
|
|
168 |
|
Consolidated Adjusted EBITDA |
$ |
869 |
|
|
$ |
466 |
|
|
$ |
3,065 |
|
|
$ |
1,667 |
|
Adjustment for non-controlling interest |
(42 |
) |
|
(11 |
) |
|
(116 |
) |
|
(129 |
) |
Adjusted EBITDA attributable to Diamondback
Energy, Inc |
$ |
827 |
|
|
$ |
455 |
|
|
$ |
2,949 |
|
|
$ |
1,538 |
|
|
|
|
|
|
|
|
|
Adjusted EBITDA per common
share: |
|
|
|
|
|
|
|
Basic |
$ |
5.17 |
|
|
$ |
3.73 |
|
|
$ |
18.04 |
|
|
$ |
14.71 |
|
Diluted |
$ |
5.16 |
|
|
$ |
3.72 |
|
|
$ |
18.00 |
|
|
$ |
14.67 |
|
Weighted average common shares
outstanding: |
|
|
|
|
|
|
|
Basic |
159,998 |
|
|
122,510 |
|
|
163,493 |
|
|
104,622 |
|
Diluted |
160,154 |
|
|
122,739 |
|
|
163,843 |
|
|
104,929 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted net income is a non-GAAP financial
measure equal to net income attributable to Diamondback Energy,
Inc. adjusted for non-cash gain on derivative instruments, gain on
revaluation of investments, loss on extinguishment of debt,
impairment of oil and natural gas properties and related income tax
adjustments. The Company’s computation of adjusted net income may
not be comparable to other similarly titled measures of other
companies or to such measure in our credit facility or any of our
other contracts.
The following table presents a reconciliation of adjusted net
income to net income:
|
Diamondback
Energy, Inc. |
Adjusted Net
Income |
(unaudited,
in millions, except share amounts and per share data) |
|
|
|
|
|
|
|
Three Months EndedDecember 31, 2019 |
|
Year Ended December 31, 2019 |
|
Pre-TaxAmounts |
|
|
Amounts Per Share |
|
Pre-Tax Amounts |
|
|
Amounts Per Share |
Net income (loss) attributable to Diamondback
Energy, Inc |
$ |
(487 |
) |
|
(3.04 |
) |
|
$ |
240 |
|
|
$ |
1.47 |
|
Non-cash gain on derivative instruments |
158 |
|
|
0.99 |
|
|
188 |
|
|
1.15 |
|
Gain on revaluation of investments |
(1 |
) |
|
(0.01 |
) |
|
(5 |
) |
|
(0.03 |
) |
Loss on extinguishment of debt |
56 |
|
|
0.35 |
|
|
56 |
|
|
0.34 |
|
Impairment of oil and natural gas properties |
790 |
|
|
4.94 |
|
|
790 |
|
|
4.82 |
|
Adjusted income excluding above items |
516 |
|
|
3.23 |
|
|
1,269 |
|
|
7.75 |
|
Income tax adjustment for above items |
(208 |
) |
|
(1.30 |
) |
|
(134 |
) |
|
(0.82 |
) |
Adjusted net income |
$ |
308 |
|
|
$ |
1.93 |
|
|
$ |
1,135 |
|
|
$ |
6.93 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PV-10
PV-10 is the Company's estimate of the present
value of the future net revenues from proved oil and gas reserves
after deducting estimated production and ad valorem taxes, future
capital costs and operating expenses, but before deducting any
estimates of future income taxes. The estimated future net
revenues are discounted at an annual rate of 10% to determine their
"present value." The Company believes PV-10 to be an
important measure for evaluating the relative significance of its
oil and gas properties and that the presentation of the non-GAAP
financial measure of PV-10 provides useful information to investors
because it is widely used by professional analysts and investors in
evaluating oil and gas companies. Because there are many
unique factors that can impact an individual company when
estimating the amount of future income taxes to be paid, the
Company believes the use of a pre-tax measure is valuable for
evaluating the Company. The Company believes that PV-10 is a
financial measure routinely used and calculated similarly by other
companies in the oil and gas industry.
The following table reconciles PV-10 to the
Company's standardized measure of discounted future net cash flows,
the most directly comparable measure calculated and presented in
accordance with GAAP. PV-10 should not be considered as an
alternative to the standardized measure as computed under GAAP.
|
|
(in
millions) |
December 31, 2019 |
Standardized measure of
discounted future net cash flows |
$ |
10,184 |
|
Add: Present value of future
income tax discounted at 10% |
1,075 |
|
PV-10 |
$ |
11,259 |
|
|
|
|
|
Derivatives
As of the filing date, the Company had the
following outstanding derivative contracts. The Company’s
derivative contracts are based upon reported settlement prices on
commodity exchanges, with crude oil derivative settlements based on
New York Mercantile Exchange West Texas Intermediate pricing and
Crude Oil Brent and with natural gas derivative settlements based
on the New York Mercantile Exchange Henry Hub pricing. When
aggregating multiple contracts, the weighted average contract price
is disclosed.
|
|
|
Crude Oil
(Bbls/day, $/Bbl) |
|
|
Q1 2020 |
|
|
Q2 2020 |
|
|
Q3 2020 |
|
|
Q4 2020 |
Swaps - WTI (Cushing) |
15,681 |
|
|
15,000 |
|
|
11,000 |
|
|
11,000 |
|
$ |
57.65 |
|
|
$ |
57.52 |
|
|
$ |
58.13 |
|
|
$ |
58.13 |
Swaps - WTI
(Magellan East Houston) |
6,000 |
|
|
6,000 |
|
|
6,000 |
|
|
6,000 |
|
$ |
62.80 |
|
|
$ |
62.80 |
|
|
$ |
62.80 |
|
|
$ |
62.80 |
|
Swaps -
Crude Brent Oil |
14,533 |
|
|
13,000 |
|
|
7,000 |
|
|
7,000 |
|
$ |
61.34 |
|
|
$ |
60.84 |
|
|
$ |
60.74 |
|
|
$ |
60.74 |
|
Three-Way Collar - WTI (Cushing) |
19,700 |
|
|
19,700 |
|
|
17,700 |
|
|
17,700 |
|
Short Put
Price ($/Bbl) |
$ |
43.98 |
|
|
$ |
43.98 |
|
|
$ |
44.44 |
|
|
$ |
44.44 |
|
Long Put
Price ($/Bbl) |
$ |
53.98 |
|
|
$ |
53.98 |
|
|
$ |
54.44 |
|
|
$ |
54.44 |
|
Ceiling
Price ($/Bbl) |
$ |
65.18 |
|
|
$ |
65.18 |
|
|
$ |
65.68 |
|
|
$ |
65.68 |
|
Three-Way Collar - WTI (Magellan East
Houston) |
14,000 |
|
|
14,000 |
|
|
14,000 |
|
|
14,000 |
|
Short Put
Price ($/Bbl) |
$ |
50.00 |
|
|
$ |
50.00 |
|
|
$ |
50.00 |
|
|
$ |
50.00 |
|
Long Put
Price ($/Bbl) |
$ |
60.00 |
|
|
$ |
60.00 |
|
|
$ |
60.00 |
|
|
$ |
60.00 |
|
Ceiling
Price ($/Bbl) |
$ |
68.61 |
|
|
$ |
68.61 |
|
|
$ |
68.61 |
|
|
$ |
68.61 |
|
Three-Way Collar - Crude Brent Oil |
34,250 |
|
|
34,250 |
|
|
34,250 |
|
|
34,250 |
|
Short Put
Price ($/Bbl) |
$ |
50.00 |
|
|
$ |
50.00 |
|
|
$ |
50.00 |
|
|
$ |
50.00 |
|
Long Put
Price ($/Bbl) |
$ |
60.00 |
|
|
$ |
60.00 |
|
|
$ |
60.00 |
|
|
$ |
60.00 |
|
Ceiling
Price ($/Bbl) |
$ |
70.76 |
|
|
$ |
70.76 |
|
|
$ |
70.76 |
|
|
$ |
70.76 |
|
Costless Put Spreads - WTI (Cushing) |
1,632 |
|
|
2,475 |
|
|
2,475 |
|
|
2,475 |
|
Short Put
Price ($/Bbl) |
$ |
50.50 |
|
|
$ |
50.50 |
|
|
$ |
50.50 |
|
|
$ |
50.50 |
|
Long Put
Price ($/Bbl) |
$ |
60.50 |
|
|
$ |
60.50 |
|
|
$ |
60.50 |
|
|
$ |
60.50 |
|
Costless Put Spreads - Crude Brent Oil |
3,462 |
|
|
5,250 |
|
|
5,250 |
|
|
5,250 |
|
Short Put
Price ($/Bbl) |
$ |
52.38 |
|
|
$ |
52.38 |
|
|
$ |
52.38 |
|
|
$ |
52.38 |
|
Long Put
Price ($/Bbl) |
$ |
65.00 |
|
|
$ |
65.00 |
|
|
$ |
65.00 |
|
|
$ |
65.00 |
|
Basis Swaps
- WTI |
41,538 |
|
|
41,538 |
|
|
41,087 |
|
|
41,087 |
|
$ |
(1.21 |
) |
|
$ |
(1.21 |
) |
|
$ |
(1.21 |
) |
|
$ |
(1.21 |
) |
Roll Swaps -
WTI |
20,000 |
|
|
20,000 |
|
|
20,000 |
|
|
20,000 |
|
$ |
0.44 |
|
|
$ |
0.44 |
|
|
$ |
0.44 |
|
|
$ |
0.44 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (MMbtu/day, $/MMbtu) |
|
|
Q1 2020 |
|
Q2 2020 |
|
Q3 2020 |
|
Q4 2020 |
|
FY 2021 |
Natural Gas Swaps - Henry Hub |
30,000 |
|
|
30,000 |
|
|
30,000 |
|
|
30,000 |
|
|
— |
|
$ |
2.55 |
|
|
$ |
2.55 |
|
|
$ |
2.55 |
|
|
$ |
2.55 |
|
|
$ |
— |
Natural Gas Swaps - Waha Hub |
80,000 |
|
|
80,000 |
|
|
90,000 |
|
|
90,000 |
|
|
— |
|
$ |
1.68 |
|
|
$ |
1.68 |
|
|
$ |
1.58 |
|
|
$ |
1.58 |
|
|
$ |
— |
|
Natural Gas Basis Swaps - Waha Hub |
70,000 |
|
|
120,000 |
|
|
120,000 |
|
|
120,000 |
|
|
150,000 |
|
$ |
(1.19 |
) |
|
$ |
(1.46 |
) |
|
$ |
(1.46 |
) |
|
$ |
(1.46 |
) |
|
$ |
(0.70 |
) |
Investor Contact:Adam Lawlis+1
432.221.7467alawlis@diamondbackenergy.com
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