Laredo Petroleum, Inc. (NYSE: LPI) ("Laredo" or "the Company")
today announced its 2019 second-quarter results, reporting net
income attributable to common stockholders of $173.4 million, or
$0.75 per diluted share. Adjusted Net Income, a non-GAAP financial
measure, for the second quarter of 2019 was $55.5 million, or $0.24
per diluted share. Adjusted EBITDA, a non-GAAP financial measure,
for the second quarter of 2019 was $153.2 million. Please see
supplemental financial information at the end of this news release
for reconciliations of non-GAAP financial measures.
2019 Second-Quarter Highlights
- Completed the widely-spaced Yellow Rose package, which is
outperforming a directly offset tightly-spaced package by 30% based
on cumulative oil production per foot
- Produced a Company record 30,447 barrels of oil per day
("BOPD"), exceeding oil production guidance by 7% or almost 2,000
BOPD
- Reduced amount outstanding on the Company's credit facility by
$35.0 million, lowering Net Debt to Adjusted EBITDA to 1.7
timesa
- Received net cash payments of $15.8 million on settlements of
derivatives as the Company's hedges mitigated the impact of
commodity price declines
- Reduced controllable cash costs of combined unit lease
operating expenses ("LOE") and unit cash general and administrative
expenses ("G&A") to $4.69 per barrel of oil equivalent ("BOE"),
a 23% decrease from full-year 2018 results of $6.07 per BOE
"The second quarter of 2019 fully demonstrated the results of
the strategic transformation Laredo began late last year," stated
Randy A. Foutch, Chairman and Chief Executive Officer. "Well
productivity dramatically improved from 2018 as we widened spacing,
unit cash G&A decreased 36% from full-year 2018 after we
reduced personnel expenses, we paid down $35 million of debt as we
generated free cash flow during the quarter, and now we expect to
generate $30 million in free cash flow for full-year 2019."
"We believe there is still room to improve on these results,"
explained Jason Pigott, President. "We are refining our development
focus to reduce the risk of vertical interference in our
Upper/Middle Wolfcamp drilling and we are returning to areas of the
Cline where economics have become competitive as costs have come
down. High-grading inventory and further reducing costs to improve
returns facilitate our top priorities of measured oil growth with
free cash flow generation and replenishing our high-quality
inventory through bolt-on transactions."
Guidance Update
In the first half of 2019, Laredo has surpassed the Company's
production and cash flow generation expectations and is in line
with capital expenditure expectations. Accordingly, full-year 2019
oil and total production guidance and free cash flow expectations
are being increased. Laredo now expects oil production for
full-year 2019 to be flat compared to full-year 2018, an increase
from previous guidance of down 2%. Total production is now expected
to grow 14% versus previous guidance of 11% growth. These increases
in production expectations are anticipated to drive free cash flow
generationb of $30 million for full-year 2019 while operating
within our $465 million capital budget, excluding non-budgeted
acquisitions.
The Company's decision to widen development spacing to improve
well productivity, combined with sustainable operational efficiency
gains that have shortened cycle times, is driving these increased
production expectations. Increasing production assumptions, coupled
with Laredo's robust 2019 commodity hedges that mitigate the impact
of declining commodity prices, underpins Laredo's confidence in
these free cash flow projections.
E&P Update
During the second quarter of 2019, Laredo completed 12 gross
(11.5 net) horizontal wells with an average lateral length of
approximately 11,600 feet. These 12 wells were developed in two
packages, both utilizing the Company's wider-spaced development
plan. The Yellow Rose package, an eight-well co-development
package, began flowback at the end of April. After more than 100
days of production, oil productivity per lateral foot is
outperforming an offset package of tighter-spaced wells completed
in 2018 by more than 30%, reinforcing the Company's confidence in
its Upper/Middle Wolfcamp type curve.
Oil and total production both exceeded second-quarter 2019
guidance, driven by the performance of the Yellow Rose package and
wells being put on production earlier than anticipated due to
reduced cycle times. Second-quarter 2019 oil production was 30,447
BOPD and total production was 82,259 BOE per day, exceeding
Company-issued guidance by 7% and 5%, respectively.
In the third quarter of 2019, Laredo expects to complete 11
gross (11 net) widely-spaced horizontal wells with an average
completed lateral length of approximately 10,100 feet. The first
package is a four-well, single zone development package in the
Middle Wolfcamp, infilling below a previous Upper Wolfcamp
development package. The second is a seven-well, Middle Wolfcamp
co-development package. These wells will further the Company's
successful transition to wider-spacing development and will provide
additional valuable information on optimal vertical spacing.
Laredo continues to sharpen its focus on high-grading
development to optimize returns and minimize spacing risk. One
important refinement is the Company's evolving approach to
Upper/Middle Wolfcamp development. Using both proprietary and
third-party vertical spacing data to quantify productivity impacts
of the vertical distances between horizontal wells, the Company's
Upper/Middle Wolfcamp co-development strategy will now target three
landing points rather than four. Laredo expects this approach to
reduce risks associated with vertical interference and increase the
certainty of productivity expectations.
Additionally, the Company is planning to return to regions of
higher productivity in the Cline formation that are expected to
generate returns commensurate with Upper/Middle Wolfcamp targets as
drilling and completions costs have decreased. These assumptions
have been incorporated into a new Cline type curve for 10,000-foot
lateral horizontal wells in these areas. Total production
expectations for the new regional Cline type curve are 1.0 MMBOE
for the life of the well, comprised of approximately 40% oil, with
more than 60% of expected oil production recovered in the first
five years of the life of the well. The Company expects to begin
incorporating some of these Cline locations into its 2020
development program.
Laredo's successful shift to wider-spaced development is
expected to drive productivity improvements versus tighter-spaced
development, as demonstrated by the Yellow Rose package.
High-grading inventory, prioritizing development based on the
highest rate of return targets and replenishing inventory through
targeted bolt-on leasing and acquisitions are expected to sustain
these improvements and drive the Company's long-term goals of
moderate oil production growth and free cash flow generation.
Laredo Midstream Services
Laredo's investments in field infrastructure through its
wholly-owned Laredo Midstream Services LLC ("LMS") subsidiary
drive both environmental and financial benefits for the Company.
Through the first half of 2019, oil and water gathering pipelines
owned or contracted by LMS gathered more than 18,000,000 barrels of
oil and water, eliminating the need for more than 130,000
truckloads within Laredo's leasehold and producing a net financial
benefit to the Company of approximately $18 million. LMS' water
recycling plants processed more than 3,100,000 barrels of water in
the first six months of 2019 and Laredo utilized 5,900,000 barrels
of recycled water in completions activities over the same period,
reducing capital expenditures and LOE by a combined $2.2
million.
The Company continues to improve upon its peer-leading unit LOE,
driven by the field infrastructure providing a substantial and
sustainable financial benefit. Unit LOE in the first half of 2019
was $3.24 per BOE, a 14% reduction from the first half of 2018.
Laredo estimates field infrastructure benefits reduced unit LOE for
the first half of 2019 by $0.57 per BOE.
2019 Capital Program
During the second quarter of 2019, Laredo invested $116 million
in drilling and completions activities. Other expenditures incurred
during the quarter included $4 million in land-related expenditures
and data acquisition, $8 million in infrastructure, including LMS
investments, and $4 million in other capitalized costs.
Additionally, the Company completed property acquisitions for $3
million that were not previously budgeted.
Total costs incurred of $296 million in the first half of 2019,
excluding non-budgeted acquisitions, put the Company on pace to
deliver on its plan to complete 52 wells within the $465 million
capital budget and deliver $30 million in free cash flow for
full-year 2019, excluding non-budgeted acquisitions.
Liquidity
At June 30, 2019, the Company had outstanding borrowings of $235
million on its $1.1 billion senior secured credit facility,
resulting in available capacity, after reductions for outstanding
letters of credit, of $850 million. Including cash and cash
equivalents of $56 million, total liquidity was $906 million.
Subsequent to the end of the second quarter of 2019, Laredo paid
down an additional $20 million on its credit facility, resulting in
outstanding borrowings of $215 million. Including cash and cash
equivalents at July 31, 2019 of $40 million and after reductions
for outstanding letters of credit, total liquidity was $910
million.
To date, the Company has repaid $55 million of the $80 million
borrowed in the first quarter of 2019 and expects to fully repay
the $80 million by the end of the year.
Commodity Derivatives
Laredo has hedged approximately 95% of anticipated oil
production at a weighted-average floor price of $60.42 per barrel
for the remainder of 2019 and approximately 75% of anticipated oil
production at a weighted-average floor price of $58.79 for
full-year 2020. Additionally, Laredo has hedged approximately 70%
of anticipated natural gas production and 65% of anticipated
natural gas liquids ("NGL") production for the remainder of 2019
and approximately 45% of anticipated natural gas production and
approximately 30% of anticipated NGL production for full-year
2020.
Additional details of the Company's hedge positions are included
in the current Corporate Presentation available on the Company's
website at www.laredopetro.com.
Guidance
The Company is increasing its anticipated full-year 2019 total
production growth guidance to 14% and oil production guidance to
flat as compared to full-year 2018. The table below reflects the
Company's guidance for the third quarter of 2019.
|
3Q-2019E |
Total production
(MBOE/d) |
79.0 |
Oil production
(MBO/d) |
27.3 |
|
|
Average sales price
realizations (without derivatives): |
|
Oil (% of WTI) |
97% |
NGL (% of WTI) |
15% |
Natural gas (% of Henry Hub) |
20% |
|
|
Selected average costs &
expenses: |
|
Lease operating expenses ($/BOE) |
$3.35 |
Production and ad valorem taxes (% of oil, NGL and natural gas
revenues) |
6.50% |
Transportation and marketing expenses ($/BOE) |
$0.70 |
Midstream service expenses ($/BOE) |
$0.15 |
General and administrative: |
|
Cash ($/BOE) |
$1.70 |
Non-cash stock-based compensation, net ($/BOE) |
$0.65 |
Depletion, depreciation and amortization ($/BOE) |
$9.00 |
Conference Call Details
On Thursday, August 1, 2019, at 7:30 a.m. CT, Laredo will host a
conference call to discuss its second-quarter 2019 financial and
operating results and management's outlook, the content of which is
not part of this earnings release. A slide presentation providing
summary financial and statistical information that will be
discussed on the call will be posted to the Company's website and
available for review. The Company invites interested parties to
listen to the call via the Company's website at
www.laredopetro.com, under the tab for "Investor Relations."
Portfolio managers and analysts who would like to participate on
the call should dial 877.930.8286 (international dial-in
253.336.8309), using conference code 7258021, approximately 10
minutes prior to the scheduled conference time. A telephonic replay
will be available approximately two hours after the call on August
1, 2019 through Thursday, August 8, 2019. Participants may access
this replay by dialing 855.859.2056, using conference code
7258021.
About Laredo
Laredo Petroleum, Inc. is an independent energy company with
headquarters in Tulsa, Oklahoma. Laredo's business strategy is
focused on the acquisition, exploration and development of oil and
natural gas properties, and midstream and marketing services,
primarily in the Permian Basin of West Texas.
Additional information about Laredo may be found on its website
at www.laredopetro.com.
Forward-Looking Statements
This press release and any oral statements made regarding the
subject of this release, including in the conference call
referenced herein, contain forward-looking statements as defined
under 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 facts, that address
activities that Laredo assumes, plans, expects, believes, intends,
projects, estimates or anticipates (and other similar expressions)
will, should or may occur in the future are forward-looking
statements. This press release and any accompanying disclosures may
include or reference certain forward-looking, non-GAAP financial
measures, such as free cash flow, and certain related estimates
regarding future performance, results and financial position. The
forward-looking statements are based on management’s current
belief, based on currently available information, as to the outcome
and timing of future events. General risks relating to Laredo
include, but are not limited to, the decline in prices of oil,
natural gas liquids and natural gas and the related impact to
financial statements as a result of asset impairments and revisions
to reserve estimates, the increase in service and supply costs,
tariffs on steel, pipeline transportation constraints in the
Permian Basin, hedging activities, possible impacts of litigation,
the suspension or discontinuance of share repurchases at any time
and other factors, including those and other risks described in its
Annual Report on Form 10-K for the year ended December 31, 2018,
and those set forth from time to time in other filings with the
Securities and Exchange Commission ("SEC"). These documents are
available through Laredo's website at
www.laredopetro.com under the tab "Investor Relations" or
through the SEC's Electronic Data Gathering and Analysis Retrieval
System at www.sec.gov. Any of these factors could cause Laredo's
actual results and plans to differ materially from those in the
forward-looking statements. Therefore, Laredo can give no assurance
that its future results will be as estimated. Laredo does not
intend to, and disclaims any obligation to, update or revise any
forward-looking statement.
The SEC generally permits oil and natural gas companies, in
filings made with the SEC, to disclose proved reserves, which are
reserve estimates that geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions
and certain probable and possible reserves that meet the SEC's
definitions for such terms. In this press release and the
conference call, the Company may use the terms "resource potential"
and "estimated ultimate recovery," or "EURs," each of which the SEC
guidelines restrict from being included in filings with the SEC
without strict compliance with SEC definitions. These terms refer
to the Company’s internal estimates of unbooked hydrocarbon
quantities that may be potentially added to proved reserves,
largely from a specified resource play. A "resource play" is a term
used by the Company to describe an accumulation of hydrocarbons
known to exist over a large areal expanse and/or thick vertical
section potentially supporting numerous drilling locations, which,
when compared to a conventional play, typically has a lower
geological and/or commercial development risk. EURs are based on
the Company's previous operating experience in a given area and
publicly available information relating to the operations of
producers who are conducting operations in these areas. Unbooked
resource potential or EURs do not constitute reserves within the
meaning of the Society of Petroleum Engineer's Petroleum Resource
Management System or SEC rules and do not include any proved
reserves. Actual quantities of reserves that may be ultimately
recovered from the Company's interests may differ substantially
from those presented herein. Factors affecting ultimate recovery
include the scope of the Company's ongoing drilling program, which
will be directly affected by the availability of capital, decreases
in oil and natural gas prices, well spacing, drilling and
production costs, availability and cost of drilling services and
equipment, drilling results, lease expirations, transportation
constraints, regulatory approvals, negative revisions to reserve
estimates and other factors as well as actual drilling results,
including geological and mechanical factors affecting recovery
rates. Estimates of ultimate recovery from reserves may change
significantly as development of the Company's core assets provides
additional data. In addition, our production forecasts and
expectations for future periods are dependent upon many
assumptions, including estimates of production decline rates from
existing wells and the undertaking and outcome of future drilling
activity, which may be affected by significant commodity price
declines or drilling cost increases. "Type curve" refers to a
production profile of a well, or a particular category of wells,
for a specific play and/or area. In addition, the Company’s
production forecasts and expectations for future periods are
dependent upon many assumptions, including estimates of production
decline rates from existing wells and the undertaking and outcome
of future drilling activity, which may be affected by significant
commodity price declines or drilling cost increases. The
"standardized measure" of discounted future new cash flows is
calculated in accordance with SEC regulations and a discount rate
of 10%. The actual results may vary considerably and should not be
considered to represent the fair market value of the Company’s
proved reserves.
|
|
|
|
|
Laredo Petroleum, Inc.Condensed
consolidated statements of operations |
|
|
|
|
|
|
|
Three months ended June 30, |
|
Six months ended June 30, |
|
|
2019 |
|
2018 |
|
2019 |
|
2018 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited) |
|
(unaudited) |
Revenues: |
|
|
|
|
|
|
|
|
Oil, NGL and natural gas sales |
|
$ |
183,863 |
|
|
$ |
208,561 |
|
|
$ |
357,239 |
|
|
$ |
405,995 |
|
Midstream service revenues |
|
2,610 |
|
|
1,976 |
|
|
5,493 |
|
|
4,335 |
|
Sales of purchased oil |
|
30,170 |
|
|
140,509 |
|
|
62,858 |
|
|
200,412 |
|
Total revenues |
|
216,643 |
|
|
351,046 |
|
|
425,590 |
|
|
610,742 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
Lease operating expenses |
|
23,632 |
|
|
22,642 |
|
|
46,241 |
|
|
44,593 |
|
Production and ad valorem taxes |
|
11,328 |
|
|
12,405 |
|
|
18,547 |
|
|
24,217 |
|
Transportation and marketing expenses |
|
4,891 |
|
|
1,534 |
|
|
9,650 |
|
|
1,534 |
|
Midstream service expenses |
|
607 |
|
|
403 |
|
|
2,210 |
|
|
1,096 |
|
Costs of purchased oil |
|
30,172 |
|
|
140,578 |
|
|
62,863 |
|
|
201,242 |
|
General and administrative |
|
11,056 |
|
|
26,834 |
|
|
32,575 |
|
|
51,559 |
|
Restructuring expenses |
|
10,406 |
|
|
— |
|
|
10,406 |
|
|
— |
|
Depletion, depreciation and amortization |
|
65,703 |
|
|
50,762 |
|
|
128,801 |
|
|
96,315 |
|
Other operating expenses |
|
1,020 |
|
|
1,121 |
|
|
2,072 |
|
|
2,227 |
|
Total costs and expenses |
|
158,815 |
|
|
256,279 |
|
|
313,365 |
|
|
422,783 |
|
Operating income |
|
57,828 |
|
|
94,767 |
|
|
112,225 |
|
|
187,959 |
|
Non-operating income
(expense): |
|
|
|
|
|
|
|
|
Gain (loss) on derivatives, net |
|
88,394 |
|
|
(45,976 |
) |
|
40,029 |
|
|
(36,966 |
) |
Interest expense |
|
(15,765 |
) |
|
(14,424 |
) |
|
(31,312 |
) |
|
(27,942 |
) |
Litigation settlement |
|
42,500 |
|
|
— |
|
|
42,500 |
|
|
— |
|
Other, net |
|
2,176 |
|
|
(915 |
) |
|
2,104 |
|
|
(3,079 |
) |
Non-operating income (expense), net |
|
117,305 |
|
|
(61,315 |
) |
|
53,321 |
|
|
(67,987 |
) |
Income before income taxes |
|
175,133 |
|
|
33,452 |
|
|
165,546 |
|
|
119,972 |
|
Income tax expense: |
|
|
|
|
|
|
|
|
Deferred |
|
(1,751 |
) |
|
— |
|
|
(1,655 |
) |
|
— |
|
Total income tax expense |
|
(1,751 |
) |
|
— |
|
|
(1,655 |
) |
|
— |
|
Net income |
|
$ |
173,382 |
|
|
$ |
33,452 |
|
|
$ |
163,891 |
|
|
$ |
119,972 |
|
Net income per common
share: |
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.75 |
|
|
$ |
0.14 |
|
|
$ |
0.71 |
|
|
$ |
0.51 |
|
Diluted |
|
$ |
0.75 |
|
|
$ |
0.14 |
|
|
$ |
0.71 |
|
|
$ |
0.51 |
|
Weighted-average common shares
outstanding: |
|
|
|
|
|
|
|
|
Basic |
|
231,406 |
|
|
230,933 |
|
|
230,943 |
|
|
234,561 |
|
Diluted |
|
231,557 |
|
|
231,706 |
|
|
231,725 |
|
|
235,501 |
|
|
|
|
|
|
Laredo Petroleum, Inc.Condensed
consolidated statements of cash flows |
|
|
|
|
|
|
|
Three months ended June 30, |
|
Six months ended June 30, |
|
|
2019 |
|
2018 |
|
2019 |
|
2018 |
|
|
|
|
|
|
|
|
|
|
|
(unaudited) |
|
(unaudited) |
Cash flows from operating
activities: |
|
|
|
|
|
|
|
|
Net income |
|
$ |
173,382 |
|
|
$ |
33,452 |
|
|
$ |
163,891 |
|
|
$ |
119,972 |
|
Adjustments to reconcile net income to net cash provided by
operating activities: |
|
|
|
|
|
|
|
|
Deferred income tax expense |
|
1,751 |
|
|
— |
|
|
1,655 |
|
|
— |
|
Depletion, depreciation and amortization |
|
65,703 |
|
|
50,762 |
|
|
128,801 |
|
|
96,315 |
|
Non-cash stock-based compensation, net |
|
(423 |
) |
|
10,676 |
|
|
6,983 |
|
|
20,015 |
|
Mark-to-market on derivatives: |
|
|
|
|
|
|
|
|
(Gain) loss on derivatives, net |
|
(88,394 |
) |
|
45,976 |
|
|
(40,029 |
) |
|
36,966 |
|
Settlements received (paid) for matured derivatives, net |
|
23,480 |
|
|
181 |
|
|
23,582 |
|
|
(2,055 |
) |
Settlements paid for early terminations of derivatives,
net |
|
(5,409 |
) |
|
— |
|
|
(5,409 |
) |
|
— |
|
Premiums paid for derivatives |
|
(2,233 |
) |
|
(5,451 |
) |
|
(6,249 |
) |
|
(9,475 |
) |
Other, net |
|
4,413 |
|
|
3,636 |
|
|
12,189 |
|
|
8,944 |
|
Cash flows from operating activities before changes in assets and
liabilities |
|
172,270 |
|
|
139,232 |
|
|
285,414 |
|
|
270,682 |
|
Decrease (increase) in current assets and liabilities,
net |
|
9,628 |
|
|
(24,867 |
) |
|
(27,122 |
) |
|
(9,372 |
) |
Decrease in noncurrent assets and liabilities, net |
|
1,913 |
|
|
1,765 |
|
|
2,977 |
|
|
1,291 |
|
Net cash provided by operating activities |
|
183,811 |
|
|
116,130 |
|
|
261,269 |
|
|
262,601 |
|
Cash flows from investing
activities: |
|
|
|
|
|
|
|
|
Acquisitions of oil and natural gas properties |
|
(2,880 |
) |
|
(16,340 |
) |
|
(2,880 |
) |
|
(16,340 |
) |
Capital expenditures: |
|
|
|
|
|
|
|
|
Oil and natural gas properties |
|
(131,887 |
) |
|
(146,509 |
) |
|
(284,616 |
) |
|
(341,534 |
) |
Midstream service assets |
|
(3,187 |
) |
|
(1,843 |
) |
|
(5,449 |
) |
|
(5,205 |
) |
Other fixed assets |
|
(460 |
) |
|
(1,002 |
) |
|
(965 |
) |
|
(4,965 |
) |
Proceeds from disposition of assets, net of selling
costs |
|
893 |
|
|
11,296 |
|
|
936 |
|
|
13,972 |
|
Net cash used in investing activities |
|
(137,521 |
) |
|
(154,398 |
) |
|
(292,974 |
) |
|
(354,072 |
) |
Cash flows from financing
activities: |
|
|
|
|
|
|
|
|
Borrowings on Senior Secured Credit Facility |
|
— |
|
|
55,000 |
|
|
80,000 |
|
|
110,000 |
|
Payments on Senior Secured Credit Facility |
|
(35,000 |
) |
|
— |
|
|
(35,000 |
) |
|
— |
|
Share repurchases |
|
— |
|
|
(33,504 |
) |
|
— |
|
|
(87,218 |
) |
Other, net |
|
(34 |
) |
|
(2,513 |
) |
|
(2,646 |
) |
|
(6,866 |
) |
Net cash (used in) provided by financing activities |
|
(35,034 |
) |
|
18,983 |
|
|
42,354 |
|
|
15,916 |
|
Net increase (decrease) in
cash and cash equivalents |
|
11,256 |
|
|
(19,285 |
) |
|
10,649 |
|
|
(75,555 |
) |
Cash and cash equivalents,
beginning of period |
|
44,544 |
|
|
55,889 |
|
|
45,151 |
|
|
112,159 |
|
Cash and cash equivalents, end
of period |
|
$ |
55,800 |
|
|
$ |
36,604 |
|
|
$ |
55,800 |
|
|
$ |
36,604 |
|
|
|
|
|
|
Laredo Petroleum, Inc.Selected operating
data |
|
|
|
|
|
|
|
Three months ended June 30, |
|
Six months ended June 30, |
|
|
2019 |
|
2018 |
|
2019 |
|
2018 |
|
|
|
|
|
|
|
|
|
|
|
(unaudited) |
|
(unaudited) |
Sales volumes: |
|
|
|
|
|
|
|
|
Oil (MBbl) |
|
2,771 |
|
|
2,514 |
|
|
5,305 |
|
|
4,953 |
|
NGL (MBbl) |
|
2,200 |
|
|
1,778 |
|
|
4,299 |
|
|
3,341 |
|
Natural gas (MMcf) |
|
15,092 |
|
|
10,947 |
|
|
27,941 |
|
|
21,120 |
|
Oil equivalents (MBOE)(1)(2) |
|
7,485 |
|
|
6,116 |
|
|
14,260 |
|
|
11,814 |
|
Average daily sales volumes (BOE/D)(2) |
|
82,259 |
|
|
67,206 |
|
|
78,787 |
|
|
65,270 |
|
% Oil(2) |
|
37 |
% |
|
41 |
% |
|
37 |
% |
|
42 |
% |
Average sales prices(2): |
|
|
|
|
|
|
|
|
Oil, without derivatives ($/Bbl)(3) |
|
$ |
57.76 |
|
|
$ |
63.26 |
|
|
$ |
54.52 |
|
|
$ |
62.58 |
|
NGL, without derivatives ($/Bbl)(3) |
|
$ |
10.09 |
|
|
$ |
20.71 |
|
|
$ |
12.66 |
|
|
$ |
19.51 |
|
Natural gas, without derivatives ($/Mcf)(3) |
|
$ |
0.11 |
|
|
$ |
1.16 |
|
|
$ |
0.49 |
|
|
$ |
1.46 |
|
Average sales price, without derivatives ($/BOE)(3) |
|
$ |
24.56 |
|
|
$ |
34.10 |
|
|
$ |
25.05 |
|
|
$ |
34.37 |
|
Oil, with derivatives ($/Bbl)(4) |
|
$ |
56.65 |
|
|
$ |
58.71 |
|
|
$ |
52.36 |
|
|
$ |
58.62 |
|
NGL, with derivatives ($/Bbl)(4) |
|
$ |
12.82 |
|
|
$ |
20.07 |
|
|
$ |
14.04 |
|
|
$ |
19.15 |
|
Natural gas, with derivatives ($/Mcf)(4) |
|
$ |
1.17 |
|
|
$ |
1.72 |
|
|
$ |
1.14 |
|
|
$ |
1.78 |
|
Average sales price, with derivatives ($/BOE)(4) |
|
$ |
27.09 |
|
|
$ |
33.04 |
|
|
$ |
25.94 |
|
|
$ |
33.18 |
|
Selected average costs and
expenses per BOE sold(2): |
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
3.16 |
|
|
$ |
3.70 |
|
|
$ |
3.24 |
|
|
$ |
3.78 |
|
Production and ad valorem taxes |
|
1.51 |
|
|
2.03 |
|
|
1.30 |
|
|
2.05 |
|
Transportation and marketing expenses |
|
0.65 |
|
|
0.25 |
|
|
0.68 |
|
|
0.13 |
|
Midstream service expenses |
|
0.08 |
|
|
0.07 |
|
|
0.15 |
|
|
0.09 |
|
General and administrative: |
|
|
|
|
|
|
|
|
Cash |
|
1.53 |
|
|
2.64 |
|
|
1.79 |
|
|
2.67 |
|
Non-cash stock-based compensation, net(5) |
|
(0.06 |
) |
|
1.75 |
|
|
0.49 |
|
|
1.69 |
|
Depletion, depreciation and amortization |
|
8.78 |
|
|
8.30 |
|
|
9.03 |
|
|
8.15 |
|
Total selected costs and expenses |
|
$ |
15.65 |
|
|
$ |
18.74 |
|
|
$ |
16.68 |
|
|
$ |
18.56 |
|
Average cash margins per BOE
sold(2)(6): |
|
|
|
|
|
|
|
|
Without derivatives |
|
$ |
17.63 |
|
|
$ |
25.41 |
|
|
$ |
17.89 |
|
|
$ |
25.65 |
|
With derivatives |
|
$ |
20.16 |
|
|
$ |
24.35 |
|
|
$ |
18.78 |
|
|
$ |
24.46 |
|
_______________________________________________________________________________
- BOE is calculated using a conversion rate of six Mcf per one
Bbl.
- The numbers presented are based on actual amounts and are not
calculated using the rounded numbers presented in the table
above.
- Actual prices received when control passes to the
purchaser/customer adjusted for quality, transportation fees,
geographical differentials, marketing bonuses or deductions and
other factors affecting the price received at the wellhead.
- Price reflects the after-effects of our derivative transactions
on our average sales prices. Our calculation of such after-effects
includes settlements of matured derivatives during the respective
periods in accordance with GAAP and an adjustment to reflect
premiums incurred previously or upon settlement that are
attributable to derivatives that settled during the respective
periods.
- For the three and six months ended June 30, 2019, non-cash
stock-based compensation, net, excluding forfeitures related to our
April 2019 organizational restructuring, on a per BOE sold basis
was $0.75 and $0.91, respectively.
- On a per BOE basis, average cash margins are calculated as
average sales price less, (i) lease operating expenses, (ii)
production and ad valorem taxes, (iii) transportation and marketing
expenses, (iv) midstream service expenses and (v) cash general and
administrative.
|
Laredo Petroleum, Inc.Costs
incurred |
The following table presents costs incurred in the acquisition,
exploration and development of oil and natural gas properties, with
asset retirement obligations included in evaluated property
acquisition costs and development costs, for the periods
presented: |
|
|
|
|
|
|
|
Three months ended June 30, |
|
Six months ended June 30, |
(in thousands) |
|
2019 |
|
2018 |
|
2019 |
|
2018 |
|
|
|
|
|
|
|
|
|
|
|
(unaudited) |
|
(unaudited) |
Property acquisition
costs(1): |
|
|
|
|
|
|
|
|
Evaluated |
|
$ |
— |
|
|
$ |
13,847 |
|
|
$ |
— |
|
|
$ |
13,847 |
|
Unevaluated |
|
2,880 |
|
|
2,790 |
|
|
2,880 |
|
|
2,790 |
|
Exploration costs |
|
5,116 |
|
|
5,108 |
|
|
12,621 |
|
|
11,245 |
|
Development costs |
|
123,664 |
|
|
178,796 |
|
|
276,381 |
|
|
327,834 |
|
Total costs incurred |
|
$ |
131,660 |
|
|
$ |
200,541 |
|
|
$ |
291,882 |
|
|
$ |
355,716 |
|
_____________________________________________________________________________
- See Note 3.a in the second-quarter 2018 Quarterly Report for
discussion of the Company's acquisitions of evaluated and
unevaluated oil and natural gas properties during the three months
ended June 30, 2018.
|
|
|
|
|
Laredo Petroleum, Inc.Supplemental
reconciliations of GAAP to non-GAAP financial
measures |
Non-GAAP financial measuresThe non-GAAP financial
measures of Adjusted Net Income, Adjusted EBITDA, Net Debt to
Adjusted EBITDA and Projected Free Cash Flow, as defined by us, may
not be comparable to similarly titled measures used by other
companies. Therefore, these non-GAAP measures should be considered
in conjunction with net income or loss and other performance
measures prepared in accordance with GAAP, such as operating income
or loss or cash flows from operating activities. Adjusted Net
Income and Adjusted EBITDA should not be considered in isolation or
as a substitute for GAAP measures, such as net income or loss,
operating income or loss or any other GAAP measure of liquidity or
financial performance.Adjusted Net Income
(Unaudited)Adjusted Net Income is a non-GAAP
financial measure we use to evaluate performance, prior to income
taxes, mark-to-market on derivatives, premiums paid for
derivatives, gains or losses on disposal of assets and other
non-recurring income and expenses and after applying adjusted
income tax expense. We believe Adjusted Net Income helps investors
in the oil and natural gas industry to measure and compare our
performance to other oil and natural gas companies by excluding
from the calculation items that can vary significantly from company
to company depending upon accounting methods, the book value of
assets and other non-operational factors.The following table
presents a reconciliation of income before income taxes (GAAP) to
Adjusted Net Income (non-GAAP): |
|
|
|
|
|
|
|
Three months ended June 30, |
|
Six months ended June 30, |
(in thousands, except per share data) |
|
2019 |
|
2018 |
|
2019 |
|
2018 |
|
|
|
|
|
|
|
|
|
|
|
(unaudited) |
|
(unaudited) |
Income before income
taxes |
|
$ |
175,133 |
|
|
$ |
33,452 |
|
|
$ |
165,546 |
|
|
$ |
119,972 |
|
Plus: |
|
|
|
|
|
|
|
|
Mark-to-market on derivatives: |
|
|
|
|
|
|
|
|
(Gain) loss on derivatives, net |
|
(88,394 |
) |
|
45,976 |
|
|
(40,029 |
) |
|
36,966 |
|
Settlements received (paid) for matured derivatives, net |
|
23,480 |
|
|
181 |
|
|
23,582 |
|
|
(2,055 |
) |
Settlements paid for early terminations of derivatives,
net |
|
(5,409 |
) |
|
— |
|
|
(5,409 |
) |
|
— |
|
Premiums paid for derivatives |
|
(2,233 |
) |
|
(5,451 |
) |
|
(6,249 |
) |
|
(9,475 |
) |
Restructuring expenses |
|
10,406 |
|
|
— |
|
|
10,406 |
|
|
— |
|
Litigation settlement |
|
(42,500 |
) |
|
— |
|
|
(42,500 |
) |
|
— |
|
Loss on disposal of assets, net |
|
670 |
|
|
1,358 |
|
|
1,609 |
|
|
3,975 |
|
Adjusted income before adjusted income tax expense |
|
71,153 |
|
|
75,516 |
|
|
106,956 |
|
|
149,383 |
|
Adjusted income tax expense(1) |
|
(15,654 |
) |
|
(16,614 |
) |
|
(23,530 |
) |
|
(32,864 |
) |
Adjusted Net Income |
|
$ |
55,499 |
|
|
$ |
58,902 |
|
|
$ |
83,426 |
|
|
$ |
116,519 |
|
Net income per common
share: |
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.75 |
|
|
$ |
0.14 |
|
|
$ |
0.71 |
|
|
$ |
0.51 |
|
Diluted |
|
$ |
0.75 |
|
|
$ |
0.14 |
|
|
$ |
0.71 |
|
|
$ |
0.51 |
|
Adjusted Net Income per common
share: |
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.24 |
|
|
$ |
0.26 |
|
|
$ |
0.36 |
|
|
$ |
0.50 |
|
Diluted |
|
$ |
0.24 |
|
|
$ |
0.25 |
|
|
$ |
0.36 |
|
|
$ |
0.49 |
|
Weighted-average common shares
outstanding: |
|
|
|
|
|
|
|
|
Basic |
|
231,406 |
|
|
230,933 |
|
|
230,943 |
|
|
234,561 |
|
Diluted |
|
231,557 |
|
|
231,706 |
|
|
231,725 |
|
|
235,501 |
|
_______________________________________________________________________________
- Adjusted income tax expense is calculated by applying a
statutory tax rate of 22% for each of the periods ended
June 30, 2019 and 2018.
Adjusted EBITDA (Unaudited)
Adjusted EBITDA is a non-GAAP financial measure that we define
as net income or loss plus adjustments for income taxes, depletion,
depreciation and amortization, non-cash stock-based compensation,
net, accretion expense, mark-to-market on derivatives, premiums
paid for derivatives, interest expense, gains or losses on disposal
of assets and other non-recurring income and expenses. Adjusted
EBITDA provides no information regarding a company's capital
structure, borrowings, interest costs, capital expenditures,
working capital movement or tax position. Adjusted EBITDA does not
represent funds available for discretionary use because those funds
are required for debt service, capital expenditures, working
capital, income taxes, franchise taxes and other commitments and
obligations. However, our management believes Adjusted EBITDA is
useful to an investor in evaluating our operating performance
because this measure:
- is widely used by investors in the oil and natural gas industry
to measure a company's operating performance without regard to
items excluded from the calculation of such term, which can vary
substantially from company to company depending upon accounting
methods, the book value of assets, capital structure and the method
by which assets were acquired, among other factors;
- helps investors to more meaningfully evaluate and compare the
results of our operations from period to period by removing the
effect of our capital structure from our operating structure;
and
- is used by our management for various purposes, including as a
measure of operating performance, in presentations to our board of
directors and as a basis for strategic planning and
forecasting.
There are significant limitations to the use of Adjusted EBITDA
as a measure of performance, including the inability to analyze the
effect of certain recurring and non-recurring items that materially
affect our net income or loss, the lack of comparability of results
of operations to different companies and the different methods of
calculating Adjusted EBITDA reported by different companies. Our
measurements of Adjusted EBITDA for financial reporting as compared
to compliance under our debt agreements differ.
The following table presents a reconciliation of net income
(GAAP) to Adjusted EBITDA (non-GAAP):
|
|
Three months ended June 30, |
|
Six months ended June 30, |
(in thousands) |
|
2019 |
|
2018 |
|
2019 |
|
2018 |
|
|
|
|
|
|
|
|
|
|
|
(unaudited) |
|
(unaudited) |
Net income |
|
$ |
173,382 |
|
|
$ |
33,452 |
|
|
$ |
163,891 |
|
|
$ |
119,972 |
|
Plus: |
|
|
|
|
|
|
|
|
Deferred income tax expense |
|
1,751 |
|
|
— |
|
|
1,655 |
|
|
— |
|
Depletion, depreciation and amortization |
|
65,703 |
|
|
50,762 |
|
|
128,801 |
|
|
96,315 |
|
Non-cash stock-based compensation, net |
|
(423 |
) |
|
10,676 |
|
|
6,983 |
|
|
20,015 |
|
Restructuring expenses |
|
10,406 |
|
|
— |
|
|
10,406 |
|
|
— |
|
Accretion expense |
|
1,020 |
|
|
1,121 |
|
|
2,072 |
|
|
2,227 |
|
Mark-to-market on derivatives: |
|
|
|
|
|
|
|
|
(Gain) loss on derivatives, net |
|
(88,394 |
) |
|
45,976 |
|
|
(40,029 |
) |
|
36,966 |
|
Settlements received (paid) for matured derivatives, net |
|
23,480 |
|
|
181 |
|
|
23,582 |
|
|
(2,055 |
) |
Settlements paid for early terminations of derivatives,
net |
|
(5,409 |
) |
|
— |
|
|
(5,409 |
) |
|
— |
|
Premiums paid for derivatives |
|
(2,233 |
) |
|
(5,451 |
) |
|
(6,249 |
) |
|
(9,475 |
) |
Interest expense |
|
15,765 |
|
|
14,424 |
|
|
31,312 |
|
|
27,942 |
|
Litigation settlement |
|
(42,500 |
) |
|
— |
|
|
(42,500 |
) |
|
— |
|
Loss on disposal of assets, net |
|
670 |
|
|
1,358 |
|
|
1,609 |
|
|
3,975 |
|
Adjusted EBITDA |
|
$ |
153,218 |
|
|
$ |
152,499 |
|
|
$ |
276,124 |
|
|
$ |
295,882 |
|
a Net Debt to Adjusted EBITDA
Net debt to Adjusted EBITDA is calculated as net debt as of
June 30, 2019 divided by trailing twelve-month Adjusted EBITDA
ending June 30, 2019 of $569 million. Net debt as of
June 30, 2019 was $979 million, calculated as the face
value of debt of $1.035 billion reduced by cash and cash
equivalents of $56 million. See above for a definition of Adjusted
EBITDA.
b Projected Free Cash Flow
Projected free cash flow is calculated as estimated full-year
2019 cash flows from operating activities before changes in assets
and liabilities, less cash and non-cash capital investments made
during the period, excluding non-budgeted acquisitions. Management
believes this is useful to investors in evaluating the operating
trends in its business due to production, commodity prices,
operating costs and other related factors.
Contacts:Ron Hagood: (918) 858-5504 -
RHagood@laredopetro.com
Laredo Petroleum (NYSE:LPI)
Historical Stock Chart
From Aug 2024 to Sep 2024
Laredo Petroleum (NYSE:LPI)
Historical Stock Chart
From Sep 2023 to Sep 2024