Laredo Petroleum, Inc. (NYSE: LPI) ("Laredo" or "the Company")
today announced its 2019 third-quarter results, reporting net loss
attributable to common stockholders of $264.6 million, or $1.14 per
diluted share, which includes a non-cash full cost ceiling
impairment charge of $397.9 million. Adjusted Net Income, a
non-GAAP financial measure, for the third quarter of 2019 was $48.8
million, or $0.21 per diluted share. Adjusted EBITDA, a non-GAAP
financial measure, for the third quarter of 2019 was $146.2
million. Please see supplemental financial information at the end
of this news release for reconciliations of non-GAAP financial
measures, including a calculation of Free Cash Flow.
The Company also announced the signing of a purchase and sale
agreement to acquire 7,360 net acres and 750 net royalty acres in
Howard County for $130 million, subject to customary closing
adjustments and conditions, with closing expected late in the
fourth quarter of 2019.
2019 Third-Quarter Highlights
- Produced 27,830 barrels of oil per day ("BOPD") and 81,921
barrels of oil equivalent ("BOE") per day, exceeding oil
production guidance for the quarter by 2% and total production
guidance by 4%
- Generated $48.9 million of Free Cash Flow and reduced the
amount outstanding on the Company's credit facility by $50.0
million, maintaining Net Debt to Adjusted EBITDAa at 1.7 times
- Reduced controllable cash costs of combined unit lease
operating expenses ("LOE") and unit cash general and administrative
expenses ("G&A") to $4.41 per BOE, a 27% decrease from
full-year 2018 results of $6.07 per BOE
- Reduced well costs to $660 per lateral foot for Laredo's
standard completion design, a decrease of 14% from year-end 2018
costs of $770 per lateral foot
- Received net cash of $23.8 million on settlements of
derivatives as the Company's hedges mitigated the impact of
commodity price declines
"Beginning in late 2018 and throughout 2019, we have made a
significant transition from being a Company that sought to maximize
net asset value to being a returns and Free Cash Flowb generation
focused Company," stated Jason Pigott, President and Chief
Executive Officer. "By optimizing development spacing and driving
costs down, we substantially improved capital efficiency in 2019
and have generated almost $40 million of Free Cash Flow in the
first nine months of the year. The pending Howard County
acquisition we are announcing today is our next strategic step to
maximize and create additional value for our stakeholders.
Utilizing cash flow from our existing production base to develop
higher-margin inventory transforms our near-term development
program. Oil-rich inventory at the front of our rig schedule
creates a step change in capital efficiency, leading to increased
oil growth and Free Cash Flowb expectations in 2020 and 2021 at
lower capital spending levels."
"We do not expect this transaction to be a unique occurrence,"
continued Mr. Pigott. "We will continue to pursue acquisitions of
high-margin inventory that improve our corporate returns when
developed with cash flow from our existing production. Similar to
this transaction, we will be focused on buying assets at valuations
that are quickly accretive on a debt-adjusted per share basis and
dedicating Free Cash Flowb to debt repayment to maintain a
competitive leverage profile."
Tier-One Acreage Acquisition
On November 4, 2019, Laredo signed a purchase and sale agreement
to acquire 7,360 net acres (96% operated) and 750 net royalty acres
in Howard County for a total of $130 million. The Company believes
the opportunistic acquisition of high-margin, tier-one acreage at
values below historical averages in Howard County transforms the
Company's near-term development plan and return profile and
establishes an additional operating area in which to leverage
Laredo's basin-low cost structure.
The acreage is located in a region with significant offset
development activity. Relevant offset production indicates
first-year production that is 80% oil and first year oil
productivity that is 55% higher than expectations for legacy Laredo
Wolfcamp drilling and 20% higher than the Cline. The Company
expects to develop 120 gross (100 net) primary locations on the
acreage beginning in first-quarter 2020, targeting the Lower
Spraberry and Upper and Middle Wolfcamp formations. The Company
believes returns will be further enhanced for the locations
developed on the 750 net royalty acres, all of which will be
operated by Laredo.
The Company believes that the highly contiguous nature of the
pending leasehold acquisition will enable Laredo to maintain the
same operational efficiencies realized on the Company's existing
acreage base. The cost and efficiency advantages associated with
long-lateral drilling, limited rig and completions crew moves and
large development packages are expected to be recognized on this
acreage, with expected well costs of $660 per lateral foot for the
Company's standard completion design. Additionally, substantial
third-party infrastructure is in place, which Laredo believes will
limit the need for upfront capital expenditures prior to
development.
The pending leasehold acquisition is largely undeveloped and the
Company believes it has minimal existing parent-child
considerations. To minimize future parent-child interactions,
Laredo intends to co-develop the three primary targets with four
wells in the Lower Spraberry formation and six wells in each of the
Upper and Middle Wolfcamp formations. The first well package is
expected to be completed during the third quarter of 2020.
Laredo expects to quickly integrate the Howard County acreage
into the Company's development plan. Allocating capital to the
Howard County acreage is expected to significantly improve returns
and capital efficiency, driving updated expectations of mid-to-high
single digit annual oil growth and cumulative Free Cash Flowb
generation of $100 million in the 2020 - 2021 period.
E&P Update
During the third quarter of 2019, Laredo completed 12 gross
(12.0 net) horizontal wells, all on the Company's wider spacing
development plan, with an average completed lateral length of
10,100 feet. One of the completions was part of a nine-well package
that is expected to be fully completed in the fourth quarter of
2019. Well completions and production results exceeded
third-quarter 2019 guidance, driven by the outperformance of a
seven-well package and operational efficiencies that improved cycle
times versus expectations.
Laredo has completed four widely-spaced packages comprised of 23
wells in 2019. In total, these 23 wells are exceeding expected oil
productivity and support the Company's type curve assumptions.
Drilling and completions costs incurred of $68 million during
third-quarter 2019 benefited from improved cycle times and
additional cost reductions related to completions services and sand
procurement. Savings related to the efficiency improvements and
cost reductions have reduced well costs to $660 per lateral foot
for the Company's standard completion design, a decrease of 14%
from the end of 2018.
Laredo continues to be among the lowest cost operators in the
Midland Basin. In addition to having some of the lowest drilling
and completions costs per lateral foot, the Company has reduced
controllable cash costs to basin-leading levels. Combined unit cash
G&A costs and unit LOE totaled $4.41 per BOE in the third
quarter of 2019, a reduction from $4.69 in the second quarter of
2019.
In the fourth quarter of 2019, Laredo expects to complete 14
gross (12 net) widely-spaced horizontal wells with an average
completed lateral length of 9,900 feet. The Company is currently
operating three drilling rigs and one completions crew, which are
expected to be maintained through the remainder of 2019.
2019 Capital Program
During the third quarter of 2019, total costs incurred were $79
million, comprised of $68 million in drilling and completions
activities, $2 million in land and data related costs, $4 million
in infrastructure, including Laredo Midstream Services investments,
and $5 million in other capitalized costs.
Total costs incurred of $375 million in the first nine months of
2019, excluding non-budgeted acquisitions, put the Company on pace
to deliver on its plan to complete 58 wells within the $490 million
capital budget and deliver more than $40 million in Free Cash Flowb
for full-year 2019, excluding non-budgeted acquisitions and the
pending Howard County acquisition.
Liquidity
At September 30, 2019, the Company had outstanding borrowings of
$185 million on its $1.1 billion senior secured credit facility,
resulting in available capacity, after the reduction for
outstanding letters of credit, of $900 million. Including cash and
cash equivalents of $32 million, total liquidity was $932
million.
On October 30, 2019, pursuant to the semi-annual
redetermination, both the borrowing base and aggregate elected
commitment under the senior secured credit facility were reduced to
$1.0 billion.
Subsequent to the end of the third quarter of 2019, Laredo paid
down an additional $5 million on its credit facility, resulting in
outstanding borrowings of $180 million. Including cash and cash
equivalents at November 4, 2019 of $18 million and after
reductions for outstanding letters of credit, total liquidity was
$823 million.
Commodity Derivatives
For the remainder of 2019, Laredo has hedged 95% of anticipated
oil production at a weighted-average floor price of $60.42 per
barrel. For full-year 2020, the Company has hedged 7.54 million
barrels of oil at a weighted-average floor price of $58.79.
Additionally, Laredo has hedges in place for natural gas, natural
gas liquids, and oil and natural gas basis.
Details of the Company's hedge positions are included in the
current Corporate Presentation available on the Company's website
at www.laredopetro.com.
Guidance
The Company is reaffirming its recently updated full-year 2019
total production guidance of 79.0 MBOE per day and oil production
guidance of 28.1 MBOPD. The table below reflects the Company's
guidance for the fourth quarter of 2019.
|
4Q-2019E |
Total production (MBOE per day) |
|
76.5 |
|
Oil production (MBOPD) |
|
26.0 |
|
|
|
Average sales price
realizations (without derivatives): |
|
Oil (% of WTI) |
|
99 |
% |
NGL (% of WTI) |
|
20 |
% |
Natural gas (% of Henry Hub) |
|
29 |
% |
|
|
Selected average costs &
expenses: |
|
Lease operating expenses ($/BOE) |
$3.20 |
|
Production and ad valorem taxes (% of oil, NGL and natural gas
revenues) |
|
6.50 |
% |
Transportation and marketing expenses ($/BOE) |
$1.75 |
|
Midstream service expenses ($/BOE) |
$0.15 |
|
General and administrative: |
|
Cash ($/BOE) |
$1.60 |
|
Non-cash stock-based compensation, net ($/BOE) |
$0.50 |
|
Depletion, depreciation and amortization ($/BOE) |
$8.75 |
|
Conference Call Details
On Wednesday, November 6, 2019, at 7:30 a.m. CT, Laredo will
host a conference call to discuss its third-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 8493537, 10 minutes prior to
the scheduled conference time. A telephonic replay will be
available two hours after the call on November 6, 2019 through
Wednesday, November 13, 2019. Participants may access this replay
by dialing 855.859.2056, using conference code 8493537.
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, indicates, enables, transforms, 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 and regulations, 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.
All amounts, dollars and percentages presented in this press
release are rounded and therefore approximate.
|
Laredo Petroleum, Inc.Selected operating data |
|
|
|
Three months ended September 30, |
|
Nine months ended September 30, |
|
|
2019 |
|
2018 |
|
2019 |
|
2018 |
|
|
(unaudited) |
|
(unaudited) |
Sales volumes: |
|
|
|
|
|
|
|
|
Oil (MBbl) |
|
2,560 |
|
|
2,651 |
|
|
7,865 |
|
|
7,604 |
|
NGL (MBbl) |
|
2,344 |
|
|
1,987 |
|
|
6,643 |
|
|
5,328 |
|
Natural gas (MMcf) |
|
15,790 |
|
|
11,577 |
|
|
43,731 |
|
|
32,697 |
|
Oil equivalents (MBOE)(1)(2) |
|
7,537 |
|
|
6,567 |
|
|
21,797 |
|
|
18,381 |
|
Average daily oil equivalent sales volumes (BOE/D)(2) |
|
81,921 |
|
|
71,382 |
|
|
79,843 |
|
|
67,330 |
|
Average daily oil sales volumes (Bbl/D)(2) |
|
27,830 |
|
|
28,812 |
|
|
28,810 |
|
|
27,854 |
|
Average sales prices(2): |
|
|
|
|
|
|
|
|
Oil, without derivatives ($/Bbl)(3) |
|
$ |
55.35 |
|
|
$ |
60.36 |
|
|
$ |
54.79 |
|
|
$ |
61.80 |
|
NGL, without derivatives ($/Bbl)(3) |
|
$ |
8.75 |
|
|
$ |
25.57 |
|
|
$ |
11.28 |
|
|
$ |
21.77 |
|
Natural gas, without derivatives ($/Mcf)(3) |
|
$ |
0.48 |
|
|
$ |
1.30 |
|
|
$ |
0.48 |
|
|
$ |
1.40 |
|
Average sales price, without derivatives ($/BOE)(3) |
|
$ |
22.52 |
|
|
$ |
34.39 |
|
|
$ |
24.18 |
|
|
$ |
34.38 |
|
Oil, with derivatives ($/Bbl)(4) |
|
$ |
56.15 |
|
|
$ |
55.41 |
|
|
$ |
53.59 |
|
|
$ |
57.50 |
|
NGL, with derivatives ($/Bbl)(4) |
|
$ |
13.43 |
|
|
$ |
23.99 |
|
|
$ |
13.83 |
|
|
$ |
20.95 |
|
Natural gas, with derivatives ($/Mcf)(4) |
|
$ |
1.01 |
|
|
$ |
1.79 |
|
|
$ |
1.09 |
|
|
$ |
1.79 |
|
Average sales price, with derivatives ($/BOE)(4) |
|
$ |
25.38 |
|
|
$ |
32.78 |
|
|
$ |
25.75 |
|
|
$ |
33.04 |
|
Selected average costs and
expenses per BOE sold(2): |
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
3.00 |
|
|
$ |
3.63 |
|
|
$ |
3.16 |
|
|
$ |
3.72 |
|
Production and ad valorem taxes |
|
1.47 |
|
|
2.13 |
|
|
1.36 |
|
|
2.08 |
|
Transportation and marketing expenses |
|
0.74 |
|
|
0.77 |
|
|
0.70 |
|
|
0.36 |
|
Midstream service expenses |
|
0.16 |
|
|
0.11 |
|
|
0.16 |
|
|
0.10 |
|
General and administrative: |
|
|
|
|
|
|
|
|
Cash |
|
1.41 |
|
|
2.23 |
|
|
1.66 |
|
|
2.51 |
|
Non-cash stock-based compensation, net(5) |
|
(0.23 |
) |
|
1.33 |
|
|
0.24 |
|
|
1.56 |
|
Depletion, depreciation and amortization |
|
9.17 |
|
|
8.52 |
|
|
9.08 |
|
|
8.28 |
|
Total selected costs and expenses |
|
$ |
15.72 |
|
|
$ |
18.72 |
|
|
$ |
16.36 |
|
|
$ |
18.61 |
|
Average cash margins per BOE
sold(2)(6): |
|
|
|
|
|
|
|
|
Without derivatives |
|
$ |
15.75 |
|
|
$ |
25.52 |
|
|
$ |
17.14 |
|
|
$ |
25.61 |
|
With derivatives |
|
$ |
18.60 |
|
|
$ |
23.91 |
|
|
$ |
18.72 |
|
|
$ |
24.27 |
|
- 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 delivery
point.
- 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 nine months ended September 30, 2019,
non-cash stock-based compensation, net, excluding forfeitures
related to our organizational restructuring, on a per BOE sold
basis was $0.52 and $0.75, 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.Condensed consolidated
statements of operations |
|
|
|
Three months ended September 30, |
|
Nine months ended September 30, |
|
|
2019 |
|
2018 |
|
2019 |
|
2018 |
|
|
(unaudited) |
|
(unaudited) |
Revenues: |
Oil, NGL and natural gas sales |
|
$ |
169,751 |
|
|
$ |
225,864 |
|
|
$ |
526,990 |
|
|
$ |
631,859 |
|
Midstream service revenues |
|
3,079 |
|
|
2,255 |
|
|
8,572 |
|
|
6,590 |
|
Sales of purchased oil |
|
20,739 |
|
|
51,627 |
|
|
83,597 |
|
|
252,039 |
|
Total revenues |
|
193,569 |
|
|
279,746 |
|
|
619,159 |
|
|
890,488 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
Lease operating expenses |
|
22,597 |
|
|
23,873 |
|
|
68,838 |
|
|
68,466 |
|
Production and ad valorem taxes |
|
11,085 |
|
|
14,015 |
|
|
29,632 |
|
|
38,232 |
|
Transportation and marketing expenses |
|
5,583 |
|
|
5,036 |
|
|
15,233 |
|
|
6,570 |
|
Midstream service expenses |
|
1,191 |
|
|
728 |
|
|
3,401 |
|
|
1,824 |
|
Costs of purchased oil |
|
20,741 |
|
|
51,210 |
|
|
83,604 |
|
|
252,452 |
|
General and administrative |
|
8,852 |
|
|
23,397 |
|
|
41,427 |
|
|
74,956 |
|
Restructuring expenses |
|
5,965 |
|
|
— |
|
|
16,371 |
|
|
— |
|
Depletion, depreciation and amortization |
|
69,099 |
|
|
55,963 |
|
|
197,900 |
|
|
152,278 |
|
Impairment expense |
|
397,890 |
|
|
— |
|
|
397,890 |
|
|
— |
|
Other operating expenses |
|
1,005 |
|
|
1,114 |
|
|
3,077 |
|
|
3,341 |
|
Total costs and expenses |
|
544,008 |
|
|
175,336 |
|
|
857,373 |
|
|
598,119 |
|
Operating income (loss) |
|
(350,439 |
) |
|
104,410 |
|
|
(238,214 |
) |
|
292,369 |
|
Non-operating income
(expense): |
|
|
|
|
|
|
|
|
Gain (loss) on derivatives, net |
|
96,684 |
|
|
(32,245 |
) |
|
136,713 |
|
|
(69,211 |
) |
Interest expense |
|
(15,191 |
) |
|
(14,845 |
) |
|
(46,503 |
) |
|
(42,787 |
) |
Litigation settlement |
|
— |
|
|
— |
|
|
42,500 |
|
|
— |
|
Other, net |
|
1,850 |
|
|
(883 |
) |
|
3,954 |
|
|
(3,962 |
) |
Total non-operating income (expense), net |
|
83,343 |
|
|
(47,973 |
) |
|
136,664 |
|
|
(115,960 |
) |
Income (loss) before income taxes |
|
(267,096 |
) |
|
56,437 |
|
|
(101,550 |
) |
|
176,409 |
|
Income tax benefit
(expense): |
|
|
|
|
|
|
|
|
Current |
|
— |
|
|
381 |
|
|
— |
|
|
381 |
|
Deferred |
|
2,467 |
|
|
(1,768 |
) |
|
812 |
|
|
(1,768 |
) |
Total income tax benefit (expense) |
|
2,467 |
|
|
(1,387 |
) |
|
812 |
|
|
(1,387 |
) |
Net income (loss) |
|
$ |
(264,629 |
) |
|
$ |
55,050 |
|
|
$ |
(100,738 |
) |
|
$ |
175,022 |
|
Net income (loss) per common
share: |
|
|
|
|
|
|
|
|
Basic |
|
$ |
(1.14 |
) |
|
$ |
0.24 |
|
|
$ |
(0.44 |
) |
|
$ |
0.75 |
|
Diluted |
|
$ |
(1.14 |
) |
|
$ |
0.24 |
|
|
$ |
(0.44 |
) |
|
$ |
0.75 |
|
Weighted-average common shares
outstanding: |
|
|
|
|
|
|
|
|
Basic |
|
231,562 |
|
|
230,605 |
|
|
231,152 |
|
|
233,228 |
|
Diluted |
|
231,562 |
|
|
231,639 |
|
|
231,152 |
|
|
234,207 |
|
Laredo Petroleum, Inc.Condensed consolidated
statements of cash flows |
|
|
Three months ended September 30, |
|
Nine months ended September 30, |
|
|
2019 |
|
2018 |
|
2019 |
|
2018 |
|
|
(unaudited) |
|
(unaudited) |
Cash flows from operating
activities: |
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(264,629 |
) |
|
$ |
55,050 |
|
|
$ |
(100,738 |
) |
|
$ |
175,022 |
|
Adjustments to reconcile net income (loss) to net cash provided by
operating activities: |
|
|
|
|
|
|
|
|
Deferred income tax (benefit) expense |
|
(2,467 |
) |
|
1,768 |
|
|
(812 |
) |
|
1,768 |
|
Depletion, depreciation and amortization |
|
69,099 |
|
|
55,963 |
|
|
197,900 |
|
|
152,278 |
|
Impairment expense |
|
397,890 |
|
|
— |
|
|
397,890 |
|
|
— |
|
Non-cash stock-based compensation, net |
|
(1,739 |
) |
|
8,733 |
|
|
5,244 |
|
|
28,748 |
|
Mark-to-market on derivatives: |
|
|
|
|
|
|
|
|
(Gain) loss on derivatives, net |
|
(96,684 |
) |
|
32,245 |
|
|
(136,713 |
) |
|
69,211 |
|
Settlements received (paid) for matured derivatives, net |
|
25,245 |
|
|
(3,888 |
) |
|
48,827 |
|
|
(5,943 |
) |
Settlements paid for early terminations of derivatives, net |
|
— |
|
|
— |
|
|
(5,409 |
) |
|
— |
|
Premiums paid for derivatives |
|
(1,415 |
) |
|
(5,455 |
) |
|
(7,664 |
) |
|
(14,930 |
) |
Other, net |
|
2,606 |
|
|
3,394 |
|
|
14,795 |
|
|
12,338 |
|
Cash flows from operating activities before changes in assets and
liabilities, net |
|
127,906 |
|
|
147,810 |
|
|
413,320 |
|
|
418,492 |
|
Increase in current assets and liabilities, net |
|
(21,183 |
) |
|
(313 |
) |
|
(48,305 |
) |
|
(9,685 |
) |
(Increase) decrease in noncurrent assets and liabilities, net |
|
(1,124 |
) |
|
(1,570 |
) |
|
1,853 |
|
|
(279 |
) |
Net cash provided by operating activities |
|
105,599 |
|
|
145,927 |
|
|
366,868 |
|
|
408,528 |
|
Cash flows from investing
activities: |
|
|
|
|
|
|
|
|
Acquisitions of oil and natural gas properties |
|
— |
|
|
— |
|
|
(2,880 |
) |
|
(16,340 |
) |
Capital expenditures: |
|
|
|
|
|
|
|
|
Oil and natural gas properties |
|
(83,566 |
) |
|
(180,936 |
) |
|
(368,182 |
) |
|
(522,470 |
) |
Midstream service assets |
|
(1,292 |
) |
|
(559 |
) |
|
(6,741 |
) |
|
(5,764 |
) |
Other fixed assets |
|
(755 |
) |
|
(980 |
) |
|
(1,720 |
) |
|
(5,945 |
) |
Proceeds from disposition of assets, net of selling costs |
|
5,911 |
|
|
116 |
|
|
6,847 |
|
|
14,088 |
|
Net cash used in investing activities |
|
(79,702 |
) |
|
(182,359 |
) |
|
(372,676 |
) |
|
(536,431 |
) |
Cash flows from financing
activities: |
|
|
|
|
|
|
|
|
Borrowings on Senior Secured Credit Facility |
|
— |
|
|
80,000 |
|
|
80,000 |
|
|
190,000 |
|
Payments on Senior Secured Credit Facility |
|
(50,000 |
) |
|
(20,000 |
) |
|
(85,000 |
) |
|
(20,000 |
) |
Share repurchases |
|
— |
|
|
(9,837 |
) |
|
— |
|
|
(97,055 |
) |
Other, net |
|
(4 |
) |
|
72 |
|
|
(2,650 |
) |
|
(6,794 |
) |
Net cash (used in) provided by financing activities |
|
(50,004 |
) |
|
50,235 |
|
|
(7,650 |
) |
|
66,151 |
|
Net (decrease) increase in cash and cash equivalents |
|
(24,107 |
) |
|
13,803 |
|
|
(13,458 |
) |
|
(61,752 |
) |
Cash and cash equivalents,
beginning of period |
|
55,800 |
|
|
36,604 |
|
|
45,151 |
|
|
112,159 |
|
Cash and cash equivalents, end
of period |
|
$ |
31,693 |
|
|
$ |
50,407 |
|
|
$ |
31,693 |
|
|
$ |
50,407 |
|
|
Laredo Petroleum, Inc.Total Costs
Incurred |
The
following table presents the components of our costs incurred,
excluding non-budgeted acquisition costs: |
|
|
Three months ended September 30, |
|
Nine months ended September 30, |
(in thousands) |
|
2019 |
|
2018 |
|
2019 |
|
2018 |
|
|
(unaudited) |
|
(unaudited) |
Oil and natural gas
properties |
|
$ |
76,837 |
|
$ |
147,250 |
|
$ |
365,839 |
|
$ |
486,329 |
Midstream service assets |
|
1,147 |
|
|
383 |
|
|
7,584 |
|
|
3,649 |
|
Other fixed assets |
|
999 |
|
|
1,255 |
|
|
1,966 |
|
|
6,197 |
|
Total costs incurred, excluding non-budgeted acquisition costs |
|
$ |
78,983 |
|
|
$ |
148,888 |
|
|
$ |
375,389 |
|
|
$ |
496,175 |
|
|
Laredo Petroleum, Inc.
Supplemental reconciliations of GAAP to
non-GAAP financial measures
Non-GAAP financial measures
The non-GAAP financial measures of Free Cash Flow, 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. Free Cash Flow, 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.
Free Cash Flow (Unaudited)
Free Cash Flow does not represent funds available for future
discretionary use because those funds are required for future debt
service, capital expenditures, working capital, income taxes,
franchise taxes and other commitments and obligations. However, our
management believes Free Cash Flow is useful to management and
investors in evaluating the operating trends in its business due to
production, commodity prices, operating costs and other related
factors. There are significant limitations to the use of Free Cash
Flow as a measure of performance, including the lack of
comparability due to different methods of calculating Free Cash
Flow reported by different companies.
The following table presents a reconciliation of net cash
provided by operating activities (GAAP) to cash flows from
operating activities before changes in assets and liabilities, net
(non-GAAP), less costs incurred, excluding non-budgeted acquisition
costs, for the calculation of Free Cash Flow (non-GAAP):
|
|
Three months ended September 30, |
|
Nine months ended September 30, |
(in thousands) |
|
2019 |
|
2018 |
|
2019 |
|
2018 |
|
|
(unaudited) |
|
(unaudited) |
Net cash provided by operating
activities |
|
$ |
105,599 |
|
$ |
145,927 |
|
$ |
366,868 |
|
$ |
408,528 |
Less: |
|
|
|
|
|
|
|
|
Increase in current assets and liabilities, net |
|
(21,183 |
) |
|
(313 |
) |
|
(48,305 |
) |
|
(9,685 |
) |
(Increase) decrease in noncurrent assets and liabilities, net |
|
(1,124 |
) |
|
(1,570 |
) |
|
1,853 |
|
|
(279 |
) |
Cash flows from operating
activities before changes in assets and liabilities, net |
|
127,906 |
|
|
147,810 |
|
|
413,320 |
|
|
418,492 |
|
Less costs incurred, excluding non-budgeted acquisition costs: |
|
|
|
|
|
|
|
|
Oil and natural gas properties |
|
76,837 |
|
|
147,250 |
|
|
365,839 |
|
|
486,329 |
|
Midstream service assets |
|
1,147 |
|
|
383 |
|
|
7,584 |
|
|
3,649 |
|
Other fixed assets |
|
999 |
|
|
1,255 |
|
|
1,966 |
|
|
6,197 |
|
Total costs incurred, excluding non-budgeted acquisition costs |
|
78,983 |
|
|
148,888 |
|
|
375,389 |
|
|
496,175 |
|
Free Cash Flow |
|
$ |
48,923 |
|
|
$ |
(1,078 |
) |
|
$ |
37,931 |
|
|
$ |
(77,683 |
) |
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, impairment expense,
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 (loss)
before income taxes (GAAP) to Adjusted Net Income (non-GAAP):
|
|
Three months ended September 30, |
|
Nine months ended September 30, |
(in thousands, except per share data) |
|
2019 |
|
2018 |
|
2019 |
|
2018 |
|
|
(unaudited) |
|
(unaudited) |
Income (loss) before income
taxes |
|
$ |
(267,096 |
) |
$ |
56,437 |
|
$ |
(101,550 |
) |
$ |
176,409 |
Plus: |
|
|
|
|
|
|
|
|
Mark-to-market on derivatives: |
|
|
|
|
|
|
|
|
(Gain) loss on derivatives, net |
|
(96,684 |
) |
|
32,245 |
|
|
(136,713 |
) |
|
69,211 |
|
Settlements received (paid) for matured derivatives, net |
|
25,245 |
|
|
(3,888 |
) |
|
48,827 |
|
|
(5,943 |
) |
Settlements paid for early terminations of derivatives, net |
|
— |
|
|
— |
|
|
(5,409 |
) |
|
— |
|
Premiums paid for derivatives |
|
(1,415 |
) |
|
(5,455 |
) |
|
(7,664 |
) |
|
(14,930 |
) |
Restructuring expenses |
|
5,965 |
|
|
— |
|
|
16,371 |
|
|
— |
|
Impairment expense |
|
397,890 |
|
|
— |
|
|
397,890 |
|
|
— |
|
Litigation settlement |
|
— |
|
|
— |
|
|
(42,500 |
) |
|
— |
|
(Gain) loss on disposal of assets, net |
|
(1,294 |
) |
|
616 |
|
|
315 |
|
|
4,591 |
|
Adjusted income before adjusted income tax expense |
|
62,611 |
|
|
79,955 |
|
|
169,567 |
|
|
229,338 |
|
Adjusted income tax expense(1) |
|
(13,774 |
) |
|
(17,590 |
) |
|
(37,305 |
) |
|
(50,454 |
) |
Adjusted Net Income |
|
$ |
48,837 |
|
|
$ |
62,365 |
|
|
$ |
132,262 |
|
|
$ |
178,884 |
|
Net income (loss) per common
share: |
|
|
|
|
|
|
|
|
Basic |
|
$ |
(1.14 |
) |
|
$ |
0.24 |
|
|
$ |
(0.44 |
) |
|
$ |
0.75 |
|
Diluted |
|
$ |
(1.14 |
) |
|
$ |
0.24 |
|
|
$ |
(0.44 |
) |
|
$ |
0.75 |
|
Adjusted Net Income per common
share: |
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.21 |
|
|
$ |
0.27 |
|
|
$ |
0.57 |
|
|
$ |
0.77 |
|
Diluted |
|
$ |
0.21 |
|
|
$ |
0.27 |
|
|
$ |
0.57 |
|
|
$ |
0.76 |
|
Adjusted diluted |
|
$ |
0.21 |
|
|
$ |
0.27 |
|
|
$ |
0.57 |
|
|
$ |
0.76 |
|
Weighted-average common shares
outstanding: |
|
|
|
|
|
|
|
|
Basic |
|
231,562 |
|
|
230,605 |
|
|
231,152 |
|
|
233,228 |
|
Diluted |
|
231,562 |
|
|
231,639 |
|
|
231,152 |
|
|
234,207 |
|
Adjusted diluted |
|
231,701 |
|
|
231,639 |
|
|
231,743 |
|
|
234,207 |
|
(1)Adjusted income tax expense is calculated by applying a
statutory tax rate of 22% for each of the periods ended
September 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, impairment expense, 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 future discretionary
use because those funds are required for future 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
(loss) (GAAP) to Adjusted EBITDA (non-GAAP):
|
|
Three months ended September 30, |
|
Nine months ended September 30, |
(in thousands) |
|
2019 |
|
2018 |
|
2019 |
|
2018 |
|
|
(unaudited) |
|
(unaudited) |
Net income (loss) |
|
$ |
(264,629 |
) |
$ |
55,050 |
|
$ |
(100,738 |
) |
$ |
175,022 |
Plus: |
|
|
|
|
|
|
|
|
Income tax (benefit) expense |
|
(2,467 |
) |
|
1,387 |
|
|
(812 |
) |
|
1,387 |
|
Depletion, depreciation and amortization |
|
69,099 |
|
|
55,963 |
|
|
197,900 |
|
|
152,278 |
|
Impairment expense |
|
397,890 |
|
|
— |
|
|
397,890 |
|
|
— |
|
Non-cash stock-based compensation, net |
|
(1,739 |
) |
|
8,733 |
|
|
5,244 |
|
|
28,748 |
|
Restructuring expenses |
|
5,965 |
|
|
— |
|
|
16,371 |
|
|
— |
|
Accretion expense |
|
1,005 |
|
|
1,114 |
|
|
3,077 |
|
|
3,341 |
|
Mark-to-market on derivatives: |
|
|
|
|
|
|
|
|
(Gain) loss on derivatives, net |
|
(96,684 |
) |
|
32,245 |
|
|
(136,713 |
) |
|
69,211 |
|
Settlements received (paid) for matured derivatives, net |
|
25,245 |
|
|
(3,888 |
) |
|
48,827 |
|
|
(5,943 |
) |
Settlements paid for early terminations of derivatives, net |
|
— |
|
|
— |
|
|
(5,409 |
) |
|
— |
|
Premiums paid for derivatives |
|
(1,415 |
) |
|
(5,455 |
) |
|
(7,664 |
) |
|
(14,930 |
) |
Interest expense |
|
15,191 |
|
|
14,845 |
|
|
46,503 |
|
|
42,787 |
|
Litigation settlement |
|
— |
|
|
— |
|
|
(42,500 |
) |
|
— |
|
(Gain) loss on disposal of assets, net |
|
(1,294 |
) |
|
616 |
|
|
315 |
|
|
4,591 |
|
Adjusted EBITDA |
|
$ |
146,167 |
|
|
$ |
160,610 |
|
|
$ |
422,291 |
|
|
$ |
456,492 |
|
a Projected Free Cash Flow
Projected Free Cash Flow is calculated as estimated cash flows
from operating activities before changes in assets and liabilities,
less estimated costs incurred, excluding non-budgeted acquisition
costs, made during the period. Management believes this is useful
to management and investors in evaluating the operating trends in
its business due to production, commodity prices, operating costs
and other related factors.
b Net Debt to Adjusted EBITDA
Net Debt to Adjusted EBITDA is calculated as net debt as of
September 30, 2019 divided by trailing twelve-month Adjusted
EBITDA ending September 30, 2019 of $555 million. Net
debt as of September 30, 2019 was $953 million,
calculated as the face value of debt of $985 million reduced by
cash and cash equivalents of $32 million. Net Debt to Adjusted
EBITDA 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. See above for a definition of Adjusted EBITDA.
Contacts:Ron Hagood: (918) 858-5504 -
RHagood@laredopetro.com
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