Laredo Petroleum, Inc. (NYSE:LPI) ("Laredo" or the "Company") today
announced its 2017 fourth-quarter and full-year results. For the
fourth quarter of 2017, the Company reported net income
attributable to common stockholders of $408.6 million, or $1.70 per
diluted share, which includes a $405.9 million gain on the sale of
Laredo's investment in the Medallion-Midland Basin pipeline system.
Adjusted Net Income, a non-GAAP financial measure, for the fourth
quarter of 2017 was $44.8 million, or $0.19 per adjusted diluted
share. Adjusted EBITDA, a non-GAAP financial measure, for the
fourth quarter of 2017, was $133.8 million.
For the year ended December 31, 2017, the Company reported net
income attributable to common stockholders of $549.0 million, or
$2.29 per diluted share. Adjusted Net Income for the year ended
December 31, 2017 was $144.7 million, or $0.60 per adjusted diluted
share, and Adjusted EBITDA was $486.4 million. Please see
supplemental financial information at the end of this news release
for reconciliation of the non-GAAP financial measures.
2017 Highlights
- Produced a Company record 58,273 barrels of oil equivalent
("BOE") per day in full-year 2017, resulting in production growth
of approximately 17% from full-year 2016
- Grew proved developed reserves organically by approximately 36%
in 2017 at a proved developed finding and development ("F&D")
cost, a non-GAAP financial measure, of $7.90 per BOE
- Completed 62 horizontal development wells in 2017 at an average
anticipated well-level rate of return on invested capital of
greater than 30%
- Increased cash margin per BOE to $20.87 in full-year 2017, an
increase of 48% from full-year 2016, doubling the 24% increase in
the Company's average realized price per BOE over the same time
frame
- Reduced unit lease operating expenses ("LOE") to $3.53 per BOE
in full-year 2017, a reduction of approximately 15% from full-year
2016
- Recognized approximately $27.9 million of net cash benefits
from Laredo Midstream Services, LLC ("LMS") field infrastructure
investments through reduced capital and operating costs and
increased revenue
- Realized approximately $830 million in net proceeds from the
sale of the Company's interest in the Medallion-Midland Basin
pipeline system, enabling the Company to reduce debt by $690
million to a total debt level of $800 million, and net debt to 1.3
times annualized fourth-quarter 2017 Adjusted EBITDA
"During 2017, Laredo's development plan yielded well-level
returns on invested capital exceeding 30% while making meaningful
progress towards co-developing multiple landing points in our Upper
and Middle Wolfcamp formations," stated Randy A. Foutch, Chairman
and Chief Executive Officer. "We did experience increased cycle
times and decreased capital efficiency in the second half of the
year as we optimized completions and tested spacing with the goal
of adding additional premium locations. We are confident in our
operational abilities and remain committed to progressing towards a
high-density development plan that we believe will result in
improved long-term value creation."
"We will be announcing separately that our board of directors
has authorized a $200 million share repurchase program. We believe
having the optionality of repurchasing approximately 10% of our
outstanding shares at current market prices represents a highly
accretive use of capital. Given our view of the value of the
Company's reserves, financial position after our Medallion
divestment and the expected efficiencies as we identify additional
premium locations in our Upper and Middle Wolfcamp formations, we
believe repurchasing our shares accelerates value recognition for
our current stockholders."
E&P Update
In the fourth quarter of 2017, Laredo completed 18 horizontal
wells averaging approximately 9,500 completed lateral feet.
Fourth-quarter 2017 production was a Company record 61,922 BOE per
day, an increase of approximately 17% from fourth-quarter 2016.
During the fourth quarter of 2017, the Company completed the
six-well Kloesel package, drilled in the western Glasscock portion
of our leasehold. The package tested five discrete landing points
in a dense-spacing configuration. Initial data is affirming
pre-drill modeling and the early oil cut is positive. The package
was delayed due to drilling challenges associated with one well
testing a higher-pressure landing point and a second well
experiencing a problem with its casing. Root causes of both issues
have been identified and are not expected to impede further
activities in the area.
The performance of the Company's 114 horizontal wells to date
that utilized optimized completions combined with proprietary
analytics continues to exceed type curve expectations,
outperforming the Upper/Middle Wolfcamp three-stream type curve by
approximately 34% and the oil type curve by approximately 21%.
Production data supports Laredo's modeled expectations that wells
will perform, on average, at the Company's 1.3 million BOE type
curve as completions and spacing are modified to facilitate higher
density development and increase net asset value per two-section
spacing unit.
Utilizing the Company's comprehensive dataset, high-resolution
geomodels and predictive analytics, Laredo continues to evaluate
the spacing density of horizontal wells as they are co-developed in
multiple landing points in the Upper and Middle Wolfcamp
formations. Results of spacing tests conducted in 2017 suggest
development of up to 32 Upper and Middle Wolfcamp locations per
spacing unit is possible. Laredo plans to further evaluate this
higher-density development design in 2018 and expects approximately
60% of wells brought on production in the second half of 2018 to be
developed at this tighter spacing.
Lease operating expenses decreased to $3.22 per BOE in the
fourth quarter of 2017, down approximately 9% from third-quarter
2017. The Company continues to receive significant benefits from
prior investments in field infrastructure, which reduced unit LOE
by an estimated $0.54 per BOE.
Laredo is currently operating three horizontal rigs and expects
to complete 16 net horizontal wells with an average completed
lateral length of approximately 9,100 feet in the first quarter of
2018. Cold weather early in the first quarter of 2018 disrupted
operations, negatively impacting estimated quarterly volumes by
52,000 BOE.
The Company expects well costs in the first quarter of 2018 to
begin to trend lower as longer stage lengths, in-basin sand and
other completion design changes are implemented. Additionally,
Laredo has completed the process of selecting a second full-time
completions crew. Pricing quotes from interested parties confirmed
the Company's assumptions that current service cost increases are
minimal and we believe our average well cost savings goal of
$600,000 per well in 2018 can be achieved.
Laredo Midstream Services Update
LMS-owned field infrastructure provided net combined benefits
from increased revenue and cost savings of approximately $7.5
million in the fourth quarter of 2017. In addition to financial
benefits, LMS assets provide significant operational flexibility,
including the ability to offload Laredo's natural gas production to
alternative natural gas processing facilities. During the fourth
quarter of 2017, LMS-owned natural gas gathering assets enabled the
delivery of more than 10 million cubic feet of natural gas per day
that would have been flared had the natural gas not had access to
alternative processing facilities via LMS-owned gathering
assets.
LMS' ownership of assets that gather approximately 50% of the
Company's gross operated natural gas production increases Laredo's
confidence that temporary residue natural gas delivery issues to
the WAHA hub by gas processors will not result in substantial
flaring or production curtailments. Although Laredo has not
contracted directly for firm transportation capacity of its natural
gas, the Company believes that a combination of its processors'
firm capacity and the ability to offload LMS-gathered natural gas
to alternative processors through the LMS-owned gathering system
provides the flexibility needed to avoid substantial production
curtailments.
2017 Capital Program
During the fourth quarter of 2017, Laredo invested approximately
$160 million in exploration and development activities. Other
expenditures incurred during the quarter included approximately $4
million in bolt-on land acquisitions and lease extensions,
approximately $10 million in infrastructure held by LMS and
approximately $8 million in capitalized employee-related costs.
Liquidity
At December 31, 2017, the Company had cash and cash equivalents
of approximately $112 million and undrawn capacity under the senior
secured credit facility of $1 billion. At February 13, 2018, the
Company had cash and cash equivalents of approximately $46 million
and undrawn capacity under the senior secured credit facility of $1
billion, resulting in total liquidity of approximately $1.05
billion.
Commodity Derivatives
Laredo maintains a disciplined hedging program to reduce the
variability in its anticipated cash flow due to fluctuations in
commodity prices. The Company utilizes a combination of puts, swaps
and collars, entering into contracts solely with banks that are
part of its senior secured credit facility. Laredo currently has
hedges in place for approximately 90% of anticipated oil production
in 2018 and has increased oil hedges through 2020. Laredo has also
entered into NGL and natural gas hedges through 2018 and basis
hedges through 2019. Details of the Company's hedge positions are
included in the current Corporate Presentation available on the
Company's website at www.laredopetro.com.
Guidance
The Company is reiterating its anticipated full-year 2018
production growth guidance of at least 10% as compared to 2017. The
table below reflects the Company's guidance for the first quarter
of 2018.
|
1Q-2018E |
Total production
(MBOE/d) |
62.0 |
Oil production
(MBO/d) |
27.0 |
|
|
Price Realizations
(pre-hedge): |
|
Crude oil (% of
WTI) |
97% |
Natural gas
liquids (% of WTI) |
28% |
Natural gas (%
of Henry Hub) |
57% |
|
|
Operating Costs &
Expenses: |
|
Lease operating
expenses ($/BOE) |
$ 3.55 |
Midstream
expenses ($/BOE) |
$ 0.20 |
Production and
ad valorem taxes (% of oil, NGL and natural gas revenue) |
6.25% |
General and
administrative expenses: |
|
Cash ($/BOE) |
$ 2.90 |
Non-cash stock-based compensation ($/BOE) |
$ 1.65 |
Depletion,
depreciation and amortization ($/BOE) |
$ 7.75 |
Fourth-Quarter and Full-Year 2017 Earnings Conference
Call
Laredo will host a conference call on Thursday, February 15,
2018 at 7:30 a.m. CT (8:30 a.m. ET) to discuss its fourth-quarter
and full-year 2017 financial and operating results and management's
outlook. Individuals who would like to participate on the call
should dial 877.930.8286 (international dial-in 253.336.8309),
using conference code 2795428 or listen to the call via the
Company's website at www.laredopetro.com, under the tab for
"Investor Relations." A telephonic replay will be available
approximately two hours after the call on February 15, 2018 through
Thursday, February 22, 2018. Participants may access this replay by
dialing 855.859.2056, using conference code 2795428.
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 the transportation of oil and natural
gas from such properties, primarily in the Permian Basin in 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, including, but not limited
to, the share repurchase program, which may be suspended or
discontinued by the Company at any time, are forward-looking
statements. 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 costs, hedging activities, possible impacts of pending
or potential litigation and other factors, including those and
other risks described in its Annual Report on Form 10-K for the
year ended December 31, 2016, and those set forth from time to time
in other filings with the Securities and Exchange Commission
("SEC") including, but not limited to, its Annual Report on Form
10-K for the year ended December 31, 2017, to be filed with the
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," "type curve," 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, NGL and natural gas prices, drilling costs and production
costs, availability 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
unproved resources 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.
Laredo Petroleum,
Inc.Condensed consolidated statements of
operations
|
|
Three months ended December
31, |
|
Year ended December 31, |
(in thousands, except per share data) |
|
2017 |
|
2016 |
|
2017 |
|
2016 |
|
|
(unaudited) |
|
(unaudited) |
Revenues: |
|
|
|
|
|
|
|
|
Oil, NGL
and natural gas sales |
|
$ |
183,376 |
|
|
$ |
136,012 |
|
|
$ |
621,507 |
|
|
$ |
426,485 |
|
Midstream
service revenues |
|
2,369 |
|
|
2,421 |
|
|
10,517 |
|
|
8,342 |
|
Sales of
purchased oil |
|
54,592 |
|
|
45,881 |
|
|
190,138 |
|
|
162,551 |
|
Total
revenues |
|
240,337 |
|
|
184,314 |
|
|
822,162 |
|
|
597,378 |
|
Costs and
expenses: |
|
|
|
|
|
|
|
|
Lease
operating expenses |
|
18,359 |
|
|
17,407 |
|
|
75,049 |
|
|
75,327 |
|
Production and ad valorem taxes |
|
10,991 |
|
|
7,103 |
|
|
37,802 |
|
|
28,586 |
|
Midstream
service expenses |
|
1,113 |
|
|
1,251 |
|
|
4,099 |
|
|
4,077 |
|
Costs of
purchased oil |
|
54,247 |
|
|
48,346 |
|
|
195,908 |
|
|
169,536 |
|
General
and administrative |
|
23,707 |
|
|
25,698 |
|
|
96,312 |
|
|
91,756 |
|
Depletion, depreciation and amortization |
|
45,062 |
|
|
37,526 |
|
|
158,389 |
|
|
148,339 |
|
Impairment expense |
|
— |
|
|
— |
|
|
— |
|
|
162,027 |
|
Other
operating expenses |
|
1,025 |
|
|
1,523 |
|
|
4,931 |
|
|
5,692 |
|
Total
costs and expenses |
|
154,504 |
|
|
138,854 |
|
|
572,490 |
|
|
685,340 |
|
Operating income
(loss) |
|
85,833 |
|
|
45,460 |
|
|
249,672 |
|
|
(87,962 |
) |
Non-operating income
(expense): |
|
|
|
|
|
|
|
|
Gain
(loss) on derivatives, net |
|
(37,777 |
) |
|
(43,642 |
) |
|
350 |
|
|
(87,425 |
) |
Income
from equity method investee** |
|
575 |
|
|
3,144 |
|
|
8,485 |
|
|
9,403 |
|
Interest
expense |
|
(19,787 |
) |
|
(23,004 |
) |
|
(89,377 |
) |
|
(93,298 |
) |
Loss on
early redemption of debt |
|
(23,761 |
) |
|
— |
|
|
(23,761 |
) |
|
— |
|
Gain on
sale of investment in equity method investee** |
|
405,906 |
|
|
— |
|
|
405,906 |
|
|
— |
|
Other,
net |
|
(628 |
) |
|
(379 |
) |
|
(501 |
) |
|
(1,457 |
) |
Non-operating income (expense), net |
|
324,528 |
|
|
(63,881 |
) |
|
301,102 |
|
|
(172,777 |
) |
Income
(loss) before income taxes |
|
410,361 |
|
|
(18,421 |
) |
|
550,774 |
|
|
(260,739 |
) |
Income tax
expense: |
|
|
|
|
|
|
|
|
Current |
|
(1,800 |
) |
|
— |
|
|
(1,800 |
) |
|
— |
|
Total
income tax expense |
|
(1,800 |
) |
|
— |
|
|
(1,800 |
) |
|
— |
|
Net income
(loss) |
|
$ |
408,561 |
|
|
$ |
(18,421 |
) |
|
$ |
548,974 |
|
|
$ |
(260,739 |
) |
Net income (loss) per
common share: |
|
|
|
|
|
|
|
|
Basic |
|
$ |
1.71 |
|
|
$ |
(0.08 |
) |
|
$ |
2.30 |
|
|
$ |
(1.16 |
) |
Diluted |
|
$ |
1.70 |
|
|
$ |
(0.08 |
) |
|
$ |
2.29 |
|
|
$ |
(1.16 |
) |
Weighted-average common
shares outstanding: |
|
|
|
|
|
|
|
|
Basic |
|
239,332 |
|
|
238,047 |
|
|
239,096 |
|
|
225,512 |
|
Diluted |
|
240,289 |
|
|
238,047 |
|
|
240,122 |
|
|
225,512 |
|
Laredo Petroleum,
Inc.Condensed consolidated balance
sheets
(in thousands) |
|
December 31, 2017 |
|
December 31, 2016 |
Assets: |
|
(unaudited) |
|
(unaudited) |
Current
assets |
|
$ |
235,382 |
|
|
$ |
154,777 |
|
Property
and equipment, net |
|
1,768,385 |
|
|
1,366,867 |
|
Other
noncurrent assets, net** |
|
19,522 |
|
|
260,702 |
|
Total
assets |
|
$ |
2,023,289 |
|
|
$ |
1,782,346 |
|
Liabilities and
stockholders' equity: |
|
|
|
|
Current
liabilities |
|
$ |
277,419 |
|
|
$ |
187,945 |
|
Long-term
debt, net |
|
791,855 |
|
|
1,353,909 |
|
Other
noncurrent liabilities |
|
188,436 |
|
|
59,919 |
|
Stockholders' equity |
|
765,579 |
|
|
180,573 |
|
Total
liabilities and stockholders' equity |
|
$ |
2,023,289 |
|
|
$ |
1,782,346 |
|
Laredo Petroleum,
Inc.Condensed consolidated statements of cash
flows
|
|
Three months ended December
31, |
|
Year ended December 31, |
(in thousands) |
|
2017 |
|
2016 |
|
2017 |
|
2016 |
|
|
(unaudited) |
|
(unaudited) |
Cash flows from
operating activities: |
|
|
|
|
|
|
|
|
Net
income (loss) |
|
$ |
408,561 |
|
|
$ |
(18,421 |
) |
|
$ |
548,974 |
|
|
$ |
(260,739 |
) |
Adjustments to reconcile net income (loss) to net cash provided by
operating activities: |
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization |
|
45,062 |
|
|
37,526 |
|
|
158,389 |
|
|
148,339 |
|
Impairment expense |
|
— |
|
|
— |
|
|
— |
|
|
162,027 |
|
Gain on
sale of investment in equity method investee** |
|
(405,906 |
) |
|
— |
|
|
(405,906 |
) |
|
— |
|
Loss on
early redemption of debt |
|
23,761 |
|
|
— |
|
|
23,761 |
|
|
— |
|
Non-cash
stock-based compensation, net of amounts capitalized |
|
8,857 |
|
|
9,667 |
|
|
35,734 |
|
|
29,229 |
|
Mark-to-market on derivatives: |
|
|
|
|
|
|
|
|
(Gain)
loss on derivatives, net |
|
37,777 |
|
|
43,642 |
|
|
(350 |
) |
|
87,425 |
|
Cash
settlements received for matured derivatives, net |
|
2,792 |
|
|
37,655 |
|
|
37,583 |
|
|
195,281 |
|
Cash
settlements received for early terminations of derivatives,
net |
|
— |
|
|
— |
|
|
4,234 |
|
|
80,000 |
|
Cash
premiums paid for derivatives |
|
(12,311 |
) |
|
(2,697 |
) |
|
(25,853 |
) |
|
(89,669 |
) |
Other,
net** |
|
3,196 |
|
|
(425 |
) |
|
2,062 |
|
|
(5,848 |
) |
Cash
flows from operations before changes in assets and
liabilities |
|
111,789 |
|
|
106,947 |
|
|
378,628 |
|
|
346,045 |
|
(Increase) decrease in current assets and liabilities,
net |
|
(2,934 |
) |
|
4,016 |
|
|
2,568 |
|
|
10,669 |
|
Decrease
(increase) in other noncurrent assets and liabilities,
net |
|
4,008 |
|
|
(122 |
) |
|
3,718 |
|
|
(419 |
) |
Net cash
provided by operating activities |
|
112,863 |
|
|
110,841 |
|
|
384,914 |
|
|
356,295 |
|
Cash flows from
investing activities: |
|
|
|
|
|
|
|
|
Deposit
received for potential sale of oil and natural gas
properties |
|
— |
|
|
3,000 |
|
|
— |
|
|
3,000 |
|
Deposit
utilized for sale of oil and natural gas properties |
|
(3,000 |
) |
|
— |
|
|
(3,000 |
) |
|
— |
|
Capital
expenditures: |
|
|
|
|
|
|
|
|
Acquisitions of oil and natural gas properties |
|
— |
|
|
(9,060 |
) |
|
— |
|
|
(124,660 |
) |
Oil and
natural gas properties |
|
(156,957 |
) |
|
(83,944 |
) |
|
(538,122 |
) |
|
(360,679 |
) |
Midstream
service assets |
|
(9,207 |
) |
|
(1,009 |
) |
|
(20,887 |
) |
|
(5,240 |
) |
Other
fixed assets |
|
(1,301 |
) |
|
(6,629 |
) |
|
(4,905 |
) |
|
(7,611 |
) |
Investment in equity method investee** |
|
(7,236 |
) |
|
(10,897 |
) |
|
(31,808 |
) |
|
(69,609 |
) |
Proceeds
from disposition of equity method investee, net of selling
costs** |
|
829,615 |
|
|
— |
|
|
829,615 |
|
|
— |
|
Proceeds
from dispositions of capital assets, net of selling
costs |
|
29 |
|
|
32 |
|
|
64,157 |
|
|
397 |
|
Net cash
provided by (used in) investing activities |
|
651,943 |
|
|
(108,507 |
) |
|
295,050 |
|
|
(564,402 |
) |
Cash flows from
financing activities: |
|
|
|
|
|
|
|
|
Borrowings on Senior Secured Credit Facility |
|
35,000 |
|
|
25,000 |
|
|
190,000 |
|
|
239,682 |
|
Payments
on Senior Secured Credit Facility |
|
(190,000 |
) |
|
(25,000 |
) |
|
(260,000 |
) |
|
(304,682 |
) |
Early
redemption of debt |
|
(518,480 |
) |
|
— |
|
|
(518,480 |
) |
|
— |
|
Proceeds
from issuance of common stock, net of offering costs |
|
— |
|
|
— |
|
|
— |
|
|
276,052 |
|
Other,
net |
|
15 |
|
|
(22 |
) |
|
(11,997 |
) |
|
(1,427 |
) |
Net cash
(used in) provided by financing activities |
|
(673,465 |
) |
|
(22 |
) |
|
(600,477 |
) |
|
209,625 |
|
Net increase in cash
and cash equivalents |
|
91,341 |
|
|
2,312 |
|
|
79,487 |
|
|
1,518 |
|
Cash and cash
equivalents, beginning of period |
|
20,818 |
|
|
30,360 |
|
|
32,672 |
|
|
31,154 |
|
Cash and cash
equivalents, end of period |
|
$ |
112,159 |
|
|
$ |
32,672 |
|
|
$ |
112,159 |
|
|
$ |
32,672 |
|
Laredo Petroleum,
Inc.Selected operating data
|
|
Three months ended December
31, |
|
Year ended December 31, |
|
|
2017 |
|
2016 |
|
2017 |
|
2016 |
|
|
(unaudited) |
|
(unaudited) |
Sales volumes: |
|
|
|
|
|
|
|
|
Oil
(MBbl) |
|
2,448 |
|
2,274 |
|
9,475 |
|
8,442 |
NGL
(MBbl) |
|
1,613 |
|
1,293 |
|
5,800 |
|
4,784 |
Natural
gas (MMcf) |
|
9,818 |
|
7,935 |
|
35,972 |
|
29,535 |
Oil
equivalents (MBOE)(1)(2) |
|
5,697 |
|
4,889 |
|
21,270 |
|
18,149 |
Average
daily sales volumes (BOE/D)(2) |
|
61,922 |
|
53,141 |
|
58,273 |
|
49,586 |
%
Oil |
|
43% |
|
46% |
|
45% |
|
47% |
Average sales
prices(2): |
|
|
|
|
|
|
|
|
Oil,
realized ($/Bbl)(3) |
|
$ |
53.57 |
|
$ |
43.98 |
|
$ |
46.97 |
|
$ |
37.73 |
NGL,
realized ($/Bbl)(3) |
|
$ |
20.53 |
|
$ |
14.79 |
|
$ |
17.49 |
|
$ |
11.91 |
Natural
gas, realized ($/Mcf)(3) |
|
$ |
1.95 |
|
$ |
2.13 |
|
$ |
2.09 |
|
$ |
1.73 |
Average
price, realized ($/BOE)(3) |
|
$ |
32.19 |
|
$ |
27.82 |
|
$ |
29.22 |
|
$ |
23.50 |
Oil,
hedged ($/Bbl)(4) |
|
$ |
54.38 |
|
$ |
58.92 |
|
$ |
50.45 |
|
$ |
58.07 |
NGL,
hedged ($/Bbl)(4) |
|
$ |
19.53 |
|
$ |
14.79 |
|
$ |
16.91 |
|
$ |
11.91 |
Natural
gas, hedged ($/Mcf)(4) |
|
$ |
2.08 |
|
$ |
2.26 |
|
$ |
2.15 |
|
$ |
2.20 |
Average
price, hedged ($/BOE)(4) |
|
$ |
32.48 |
|
$ |
34.97 |
|
$ |
30.71 |
|
$ |
33.73 |
Average costs per BOE
sold(2): |
|
|
|
|
|
|
|
|
Lease
operating expenses |
|
$ |
3.22 |
|
$ |
3.56 |
|
$ |
3.53 |
|
$ |
4.15 |
Production and ad valorem taxes |
|
1.93 |
|
1.45 |
|
1.78 |
|
1.58 |
Midstream
service expenses |
|
0.20 |
|
0.26 |
|
0.19 |
|
0.22 |
General
and administrative: |
|
|
|
|
|
|
|
|
Cash |
|
2.61 |
|
3.28 |
|
2.85 |
|
3.45 |
Non-cash
stock-based compensation, net of amounts capitalized |
|
1.55 |
|
1.98 |
|
1.68 |
|
1.61 |
Depletion, depreciation and amortization |
|
7.91 |
|
7.68 |
|
7.45 |
|
8.17 |
Total
costs and expenses |
|
$ |
17.42 |
|
$ |
18.21 |
|
$ |
17.48 |
|
$ |
19.18 |
Cash margins per
BOE(2): |
|
|
|
|
|
|
|
|
Realized |
|
$ |
24.23 |
|
$ |
19.27 |
|
$ |
20.87 |
|
$ |
14.10 |
Hedged |
|
$ |
24.52 |
|
$ |
26.42 |
|
$ |
22.36 |
|
$ |
24.33 |
_______________________________________________________________________________
(1) BOE is calculated using a conversion rate of six Mcf per one
Bbl.(2) The numbers presented are based on actual results and are
not calculated using the rounded numbers presented in the table
above.(3) Realized oil, NGL and natural gas prices are the actual
prices realized at the wellhead adjusted for quality,
transportation fees, geographical differentials, marketing bonuses
or deductions and other factors affecting the price received at the
wellhead.(4) Hedged prices reflect the after-effects of our hedging
transactions on our average sales prices. Our calculation of such
after-effects includes current period settlements of matured
derivatives in accordance with GAAP and an adjustment to reflect
premiums incurred previously or upon settlement that are
attributable to instruments that settled in the period.
Laredo Petroleum,
Inc.Costs incurred
The following table presents the costs incurred in the
acquisition, exploration and development of oil, NGL and natural
gas assets:
|
|
Three months ended December
31, |
|
Year ended December 31, |
(in thousands) |
|
2017 |
|
2016 |
|
2017 |
|
2016 |
|
|
(unaudited) |
|
(unaudited) |
Property acquisition
costs: |
|
|
|
|
|
|
|
|
Evaluated(1) |
|
$ |
— |
|
$ |
— |
|
$ |
— |
|
$ |
5,905 |
Unevaluated |
|
— |
|
9,123 |
|
— |
|
119,923 |
Exploration
costs |
|
7,920 |
|
7,583 |
|
36,257 |
|
41,333 |
Development
costs(2) |
|
163,664 |
|
73,839 |
|
560,919 |
|
298,942 |
Total
costs incurred |
|
$ |
171,584 |
|
$ |
90,545 |
|
$ |
597,176 |
|
$ |
466,103 |
_______________________________________________________________________________
(1) Evaluated property acquisition costs include $1.1
million in asset retirement obligations for the year ended December
31, 2016.(2) Development costs include $0.1 million and $2.0
million in asset retirement obligations for the three months ended
December 31, 2017 and 2016, respectively, and $0.7 million and
$2.5 million for the years ended December 31, 2017 and
2016, respectively.
Laredo Petroleum,
Inc.Supplemental reconciliations of GAAP to
non-GAAP financial measures
Non-GAAP financial measures
The non-GAAP financial measures of Adjusted Net Income, Adjusted
EBITDA and proved developed Finding & Development Cost, 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 flow from operating activities.
Adjusted Net Income, Adjusted EBITDA and proved developed Finding
and Development Cost should not be considered in isolation or as a
substitute for GAAP measures, such as net income or loss, operating
income or loss, standardized measure of discounted future net cash
flows 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 tax expense or benefit,
impairment expense, mark-to-market on derivatives, cash premiums
paid for derivatives, write-off of debt issuance costs, gain on
sale of investment in equity method investee, gains or losses on
disposal of assets, loss on early redemption of debt 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.
Including a higher weighted-average common shares outstanding in
the denominator of a diluted per-share computation results in an
anti-dilutive per share amount when an entity is in a loss
position. As such, for each of the periods ended December 31, 2016,
our net loss (GAAP) per common share calculation utilizes the same
denominator for both basic and diluted net loss per common share.
However, our calculation of Adjusted Net Income (non-GAAP) results
in income for the periods presented. Therefore, we believe it
appropriate and more conservative to calculate an Adjusted diluted
weighted-average common shares outstanding utilizing our fully
dilutive weighted-average common shares. As such, for each of the
periods ended December 31, 2017 and 2016, we present a line
item that calculates Adjusted Net Income per Adjusted diluted
common share.
The following table presents a reconciliation of income (loss)
before income taxes (GAAP) to Adjusted Net Income (non-GAAP):
|
|
Three months ended December
31, |
|
Year ended December 31, |
(in thousands, except for per share data,
unaudited) |
|
2017 |
|
2016 |
|
2017 |
|
2016 |
Income (loss) before
income taxes |
|
$ |
410,361 |
|
|
$ |
(18,421 |
) |
|
$ |
550,774 |
|
|
$ |
(260,739 |
) |
Plus: |
|
|
|
|
|
|
|
|
Impairment expense |
|
— |
|
|
— |
|
|
— |
|
|
162,027 |
|
Mark-to-market on derivatives: |
|
|
|
|
|
|
|
|
(Gain)
loss on derivatives, net |
|
37,777 |
|
|
43,642 |
|
|
(350 |
) |
|
87,425 |
|
Cash
settlements received for matured derivatives, net |
|
2,792 |
|
|
37,655 |
|
|
37,583 |
|
|
195,281 |
|
Cash
settlements received for early terminations of derivatives,
net |
|
— |
|
|
— |
|
|
4,234 |
|
|
80,000 |
|
Cash
premiums paid for derivatives |
|
(12,311 |
) |
|
(2,697 |
) |
|
(25,853 |
) |
|
(89,669 |
) |
Write-off
of debt issuance costs |
|
— |
|
|
— |
|
|
— |
|
|
842 |
|
Gain on
sale of investment in equity method investee** |
|
(405,906 |
) |
|
— |
|
|
(405,906 |
) |
|
— |
|
Loss on
disposal of assets, net |
|
906 |
|
|
411 |
|
|
1,306 |
|
|
790 |
|
Loss on
early redemption of debt |
|
23,761 |
|
|
— |
|
|
23,761 |
|
|
— |
|
Adjusted
net income before adjusted income tax expense |
|
57,380 |
|
|
60,590 |
|
|
185,549 |
|
|
175,957 |
|
Adjusted
income tax expense(1) |
|
(12,624 |
) |
|
(21,812 |
) |
|
(40,821 |
) |
|
(63,345 |
) |
Adjusted
Net Income |
|
$ |
44,756 |
|
|
$ |
38,778 |
|
|
$ |
144,728 |
|
|
$ |
112,612 |
|
Net income (loss) per
common share: |
|
|
|
|
|
|
|
|
Basic |
|
$ |
1.71 |
|
|
$ |
(0.08 |
) |
|
$ |
2.30 |
|
|
$ |
(1.16 |
) |
Diluted |
|
$ |
1.70 |
|
|
$ |
(0.08 |
) |
|
$ |
2.29 |
|
|
$ |
(1.16 |
) |
Adjusted Net Income per
common share: |
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.19 |
|
|
$ |
0.16 |
|
|
$ |
0.61 |
|
|
$ |
0.50 |
|
Adjusted
diluted |
|
$ |
0.19 |
|
|
$ |
0.16 |
|
|
$ |
0.60 |
|
|
$ |
0.49 |
|
Weighted-average common
shares outstanding: |
|
|
|
|
|
|
|
|
Basic |
|
239,332 |
|
|
238,047 |
|
|
239,096 |
|
|
225,512 |
|
Diluted |
|
240,289 |
|
|
238,047 |
|
|
240,122 |
|
|
225,512 |
|
Adjusted
diluted |
|
240,289 |
|
|
243,507 |
|
|
240,122 |
|
|
228,676 |
|
_______________________________________________________________________________
(1) Adjusted income tax expense is calculated by
applying a statutory tax rate of 22% for each of the periods ended
December 31, 2017 in response to recent changes in the tax code,
and 36% for each of the periods ended December 31, 2016.
Adjusted EBITDA (Unaudited)
Adjusted EBITDA is a non-GAAP financial measure that we define
as net income or loss plus adjustments for income tax expense or
benefit, depletion, depreciation and amortization, bad debt
expense, impairment expense, non-cash stock-based compensation, net
of amounts capitalized, accretion expense, mark-to-market on
derivatives, cash premiums paid for derivatives, interest expense,
write-off of debt issuance costs, gains or losses on disposal of
assets, income or loss from equity method investee, proportionate
Adjusted EBITDA of our equity method investee 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 (loss) (GAAP) to Adjusted EBITDA (non-GAAP):
|
|
Three months ended December
31, |
|
Year ended December 31, |
(in thousands, unaudited) |
|
2017 |
|
2016 |
|
2017 |
|
2016 |
Net income
(loss) |
|
$ |
408,561 |
|
|
$ |
(18,421 |
) |
|
$ |
548,974 |
|
|
$ |
(260,739 |
) |
Plus: |
|
|
|
|
|
|
|
|
Income
tax expense |
|
1,800 |
|
|
— |
|
|
1,800 |
|
|
— |
|
Depletion, depreciation and amortization |
|
45,062 |
|
|
37,526 |
|
|
158,389 |
|
|
148,339 |
|
Impairment expense |
|
— |
|
|
— |
|
|
— |
|
|
162,027 |
|
Non-cash
stock-based compensation, net of amounts capitalized |
|
8,857 |
|
|
9,667 |
|
|
35,734 |
|
|
29,229 |
|
Accretion
expense |
|
969 |
|
|
896 |
|
|
3,791 |
|
|
3,483 |
|
Mark-to-market on derivatives: |
|
|
|
|
|
|
|
|
(Gain)
loss on derivatives, net |
|
37,777 |
|
|
43,642 |
|
|
(350 |
) |
|
87,425 |
|
Cash
settlements received for matured derivatives, net |
|
2,792 |
|
|
37,655 |
|
|
37,583 |
|
|
195,281 |
|
Cash
settlements received for early terminations of derivatives,
net |
|
— |
|
|
— |
|
|
4,234 |
|
|
80,000 |
|
Cash
premiums paid for derivatives |
|
(12,311 |
) |
|
(2,697 |
) |
|
(25,853 |
) |
|
(89,669 |
) |
Interest
expense |
|
19,787 |
|
|
23,004 |
|
|
89,377 |
|
|
93,298 |
|
Write-off
of debt issuance costs |
|
— |
|
|
— |
|
|
— |
|
|
842 |
|
Gain on
sale of investment in equity method investee** |
|
(405,906 |
) |
|
— |
|
|
(405,906 |
) |
|
— |
|
Loss on
disposal of assets, net |
|
906 |
|
|
411 |
|
|
1,306 |
|
|
790 |
|
Loss on
early redemption of debt |
|
23,761 |
|
|
— |
|
|
23,761 |
|
|
— |
|
Income
from equity method investee** |
|
(575 |
) |
|
(3,144 |
) |
|
(8,485 |
) |
|
(9,403 |
) |
Proportionate Adjusted EBITDA of equity method
investee**(1) |
|
2,326 |
|
|
6,386 |
|
|
22,081 |
|
|
20,367 |
|
Adjusted
EBITDA |
|
$ |
133,806 |
|
|
$ |
134,925 |
|
|
$ |
486,436 |
|
|
$ |
461,270 |
|
_______________________________________________________________________________
(1) Proportionate Adjusted EBITDA of Medallion, our
equity method investee through October 30, 2017, is calculated as
follows:
|
|
Three months ended December
31, |
|
Year ended December 31, |
(in thousands, unaudited) |
|
2017 |
|
2016 |
|
2017 |
|
2016 |
Income from equity
method investee |
|
$ |
575 |
|
|
$ |
3,144 |
|
|
$ |
8,485 |
|
|
$ |
9,403 |
|
Adjusted for
proportionate share of depreciation and amortization |
|
1,751 |
|
|
3,242 |
|
|
13,596 |
|
|
10,964 |
|
Proportionate Adjusted EBITDA of equity method investee |
|
$ |
2,326 |
|
|
$ |
6,386 |
|
|
$ |
22,081 |
|
|
$ |
20,367 |
|
Proved Developed Finding and Development Cost
(Unaudited)
Proved developed finding and development ("F&D") cost is
calculated by dividing (x) development costs for the period, by (y)
proved developed reserve additions for the period, defined as the
change in proved developed reserves, less purchased reserves, plus
sold reserves and plus sales volumes during the period. The method
we use to calculate our proved developed F&D cost may differ
significantly from methods used by other companies to compute
similar measures. As a result, our proved developed F&D cost
may not be comparable to similar measures provided by other
companies. We believe that providing the measure of proved
development F&D cost is useful in evaluating the cost, on a per
BOE basis, to add proved developed reserves.
However, this measure is provided in addition to, and not as an
alternative for, and should be read in conjunction with, the
information contained in our financial statements prepared in
accordance with GAAP. Due to various factors, including timing
differences in the addition of proved reserves and the related
costs to develop those reserves, proved developed F&D cost do
not necessarily reflect precisely the costs associated with
particular proved reserves. As a result of various factors that
could materially affect the timing and amounts of future increases
in proved reserves and the timing and amounts of future costs, we
cannot assure you that our future proved developed F&D cost
will not differ materially from those presented.
(dollars in millions, except per BOE amount, reserves
and sales volumes in MMBOE) |
|
Proved developed F&D |
Development costs
(x) |
|
$ |
561 |
|
|
|
|
Proved developed
reserves: |
|
|
As
of December 31, 2017 |
|
191 |
|
As
of December 31, 2016 |
|
(141 |
) |
Change in proved developed reserves |
|
50 |
|
Plus sales of proved developed reserves during 2017 |
|
— |
|
Plus 2017 sales volumes |
|
21 |
|
Proved developed reserve additions (y) |
|
71 |
|
|
|
|
Proved developed
F&D cost per BOE |
|
$ |
7.90 |
|
** On October 30, 2017, LMS, together with Medallion
Midstream Holdings, LLC ("MMH"), which is owned and controlled by
an affiliate of the third-party interest holder, The Energy &
Minerals Group ("EMG"), completed the sale of 100% of the ownership
interests in Medallion to an affiliate of Global Infrastructure
Partners ("GIP"), for cash consideration of $1.825 billion (the
"Medallion Sale"). LMS' net cash proceeds for its 49% ownership
interest in Medallion in 2017 was $829.6 million, before
post-closing adjustments and taxes, but after deduction of its
proportionate share of fees and other expenses associated with the
Medallion Sale. On February 1, 2018, closing adjustments were
finalized and LMS received additional net cash of $1.7 million for
total net cash proceeds before taxes of $831.3 million. The
Medallion Sale closed pursuant to the membership interest purchase
and sale agreement, which provides for potential post-closing
additional cash consideration that is structured based on GIP's
realized profit at exit. There can be no assurance as to when and
whether the additional consideration will be paid.
Contacts:Ron Hagood: (918) 858-5504
- RHagood@laredopetro.com
18-3
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