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MarketScreener Homepage  >  Equities  >  Nyse  >  Core Laboratories NV    CLB   NL0000200384

CORE LABORATORIES NV

(CLB)
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CORE LABORATORIES : N V MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (form 10-K)

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02/11/2019 | 04:56pm EDT
Core Laboratories N.V. is a Netherlands limited liability company. We were
established in 1936 and are one of the world's leading providers of proprietary
and patented reservoir description and production enhancement services and
products to the oil and gas industry, primarily through client relationships
with many of the world's major, national and independent oil companies.

We operate our business in two reporting segments. These complementary segments
provide different services and products and utilize different technologies for
improving reservoir performance and increasing oil and gas recovery from new and
existing fields:
•      Reservoir Description: Encompasses the characterization of petroleum

reservoir rock, fluid and gas samples to increase production and improve

recovery of oil and gas from our clients' reservoirs. We provide

laboratory-based analytical and field services to characterize properties

       of crude oil and petroleum products to the oil and gas industry. We also
       provide proprietary and joint industry studies based on these types of
       analyses.


•      Production Enhancement: Includes services and products relating to

reservoir well completions, perforations, stimulations and production. We

       provide integrated diagnostic services to evaluate and monitor the
       effectiveness of well completions and to develop solutions aimed at
       increasing the effectiveness of enhanced oil recovery projects.


General Overview


We provide services as well as design and produce products which enable our
clients to evaluate reservoir performance and increase oil and gas recovery from
new and existing fields. These services and products are generally in higher
demand when our clients are investing capital in their field development
programs that are designed to increase productivity from existing fields or when
exploring for new fields. Our clients' investment in capital expenditure
programs tends to correlate over the longer term to oil and natural gas
commodity prices. During periods of higher, stable prices, our clients generally
invest more in capital expenditures and, during periods of lower or volatile
commodity prices, they tend to invest less. Consequently, the level of capital
expenditures by our clients impacts the demand for our services and products.

The following table summarizes the annual average and year-end worldwide and
U.S. rig counts for the years ended December 31, 2018, 2017 and 2016, as well as
the annual average and year-end spot price of a barrel of WTI crude, Europe
Brent crude and an MMBtu of natural gas:
                                               2018              2017       

2016

Baker Hughes Worldwide Average Rig Count
(1)                                               2,211            2,029    

1,593

Baker Hughes U.S. Average Rig Count (1)           1,032              875    

510


Baker Hughes Worldwide Year-End Rig
Count (2)                                         2,244            2,089    

1,772

Baker Hughes U.S. Year-End Rig Count (2)          1,078              930    

634


Average Crude Oil Price per Barrel WTI
(3)                                      $        65.23$      50.80$      43.29
Average Crude Oil Price per Barrel Brent
(4)                                      $        71.34$      54.12$      43.67
Average Natural Gas Price per MMBtu (5)  $         3.15     $       2.99

$ 2.52


Year-end Crude Oil Price per Barrel WTI
(3)                                      $        45.15$      60.46$      53.75
Year-end Crude Oil Price per Barrel
Brent (4)                                $        50.57$      66.73$      54.96
Year-end Natural Gas Price per MMBtu (5) $         3.25     $       3.69$       3.71
(1) Twelve month average rig count as reported by Baker Hughes, a GE Company - Worldwide
Rig Count.
(2) Year-end rig count as reported by Baker Hughes, a GE Company - Worldwide Rig Count.
(3) Average daily and year-end West Texas Intermediate crude spot price as reported by the
U.S. Energy Information Administration.
(4) Average daily and year-end Europe Brent crude spot price as reported by the U.S. Energy
Information Administration.
(5) Average daily and year-end Henry Hub natural gas spot price as reported by the U.S.
Energy Information Administration.



The prices for both WTI and Brent crude oil showed improvement during 2017 and
continued to strengthen through most of 2018; however, they decreased
significantly during the last quarter of 2018 to end the year at levels not seen
since mid-2016.

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The improvement in crude oil prices over this two-year period led to elevated
levels in U.S. onshore activities associated with both the exploration and
production of oil; however, levels of activity outside the U.S. have remained
relatively flat.

In North America, the land-based rig count increased 45% during 2017 and another
19% during 2018, which had a positive impact for both services and product sales
to this market over this time period. Although the North America rig count had
improved by the end of 2018 it still remained almost 50% below 2014 levels. The
build in levels of activities on development projects and producing fields in
the U.S. unconventional reservoirs during 2017 continued to strengthen during
most of 2018, until October 2018 when the commodity price weakened significantly
and activity levels decreased.

Outside of North America, activities associated with the exploration for and
production of oil dropped to current lower levels during the industry downturn
which began at the end of 2014 and remained relatively flat during 2017 and
2018. Our clients' activities in the international and deepwater markets
remained at these lower levels in 2017 and 2018, and although activities have
not yet increased, we believe these markets have shown signs of recovery for
2019 and beyond as our clients have announced new capital investment projects
throughout 2017 and 2018.

Results of Operations

Operating Results for the Year Ended December 31, 2018 Compared to the Years Ended December 31, 2017 and 2016


We evaluate our operating results by analyzing revenue, operating income and
operating income margin (defined as operating income divided by total revenue).
Since we have a relatively fixed cost structure, increases in revenue generally
translate into higher operating income results. Results for the years ended
December 31, 2018, 2017 and 2016 are summarized in the following chart:

              [[Image Removed: graph2018revenueebitandmargi.gif]]



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Results of operations as a percentage of applicable revenue for the years ended
December 31, 2018, 2017 and 2016 are as follows (in thousands, except for per
share information):

                                2018                   2017                   2016            2018 / 2017   2017 / 2016
Revenue:                                                                                              % Change
Services                $ 486,820    69.5  %    $ 480,264    74.1 %   $ 468,388    79.4  %        1.4  %        2.5  %
Product Sales             214,026    30.5  %      167,555    25.9 %     121,844    20.6  %       27.7  %       37.5  %
TOTAL REVENUE             700,846   100.0  %      647,819   100.0 %     590,232   100.0  %        8.2  %        9.8  %
OPERATING EXPENSES:
Cost of services* (1)     343,833    70.6  %      333,365    69.4 %     329,520    70.4  %        3.1  %        1.2  %
Cost of product sales*
(1)                       153,131    71.5  %      131,593    78.5 %     107,983    88.6  %       16.4  %       21.9  %
Total cost of services
and product sales         496,964    70.9  %      464,958    71.8 %     437,503    74.1  %        6.9  %        6.3  %
General and
administrative expenses
(1)                        62,910     9.0  %       47,737     7.4 %      39,390     6.7  %       31.8  %       21.2  %
Depreciation and
amortization               23,087     3.3  %       24,524     3.8 %      26,288     4.5  %       (5.9 )%       (6.7 )%
Other (income) expense,
net                          (737 )  (0.1 )%          632     0.1 %        (400 )  (0.1 )%         NM            NM
OPERATING INCOME          118,622    16.9  %      109,968    17.0 %      87,451    14.8  %        7.9  %       25.7  %
Interest expense           13,328     1.9  %       10,734     1.7 %      11,572     2.0  %       24.2  %       (7.2 )%
Income before income
tax expense               105,294    15.0  %       99,234    15.3 %      75,879    12.9  %        6.1  %       30.8  %
Income tax expense         25,447     3.6  %       18,249     2.8 %      10,855     1.8  %       39.4  %       68.1  %
Income from continuing
operations                 79,847    11.4  %       80,985    12.5 %      65,024    11.0  %       (1.4 )%       24.5  %
Income (loss) from
discontinued operations       (58 )     -  %        2,111     0.3 %      (1,165 )  (0.2 )%         NM            NM
Net income                 79,789    11.4  %       83,096    12.8 %      63,859    10.8  %       (4.0 )%       30.1  %
Net income (loss)
attributable to
non-controlling
interest                      263       -  %          (29 )     - %         (36 )     -  %         NM            NM
Net income attributable
to Core Laboratories
N.V.                    $  79,526    11.3  %    $  83,125    12.8 %   $  

63,895 10.8 % (4.3 )% 30.1 %


Diluted earnings per
share from continuing
operations              $    1.80$    1.83$    1.49                  (1.6 )%       22.8  %

Diluted earnings per
share attributable to
Core Laboratories N.V.  $    1.79$    1.88$    1.46                  (4.8 )%       28.8  %

Diluted weighted
average common shares
outstanding                44,474                  44,264                43,670

*Percentage based on applicable revenue rather than total revenue.
"NM" means not meaningful.
(1) Excludes
depreciation.



Services Revenue

Services revenue, which is tied more to activities associated with the
exploration and production of oil and gas outside the U.S., increased 1.4% to
$486.8 million in 2018 from $480.3 million in 2017 which increased 2.5% from
$468.4 million in 2016. The increase in revenue was driven by a stronger U.S.
market for most of 2018, which was partially offset by a weaker market outside
the U.S. Crude oil prices continued to strengthen throughout 2018 until early
October when crude oil prices peaked and decreased over 40% by December 2018.
The improvement in crude oil prices continued to support elevated activity
levels in the U.S. onshore market for most of 2018, however activities outside
the U.S. have remained flat. Although our clients have announced Final
Investment Decisions ("FIDs") for several projects outside the U.S. and in
offshore environments, significant activity on these projects did not start in
2018 and wells must be drilled and/or completed, stimulated, cored and have
reservoir fluid samples collected, before we see a revenue opportunity. We
continue our focus on worldwide crude oil related projects, including those
related to the development of fields in onshore and offshore North America,
offshore South America, offshore Europe and Africa, the Middle East, and Asia
Pacific regions.

Product Sales Revenue

Product sales revenue, which is tied more to the completion of wells in North
America, increased 28% to $214.0 million in 2018 from $167.6 million in 2017 and
increased 38% from $121.8 million in 2016. The 28% increase in product sales
revenue

                                       20
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in 2018 compared to 2017 outpaced the 13% increase in rig count and the 25% increase in the completion of wells due to our differentiated well completion product sales surpassing the industry activity levels in North America.

Cost of Services, excluding depreciation


Cost of services increased to $343.8 million in 2018 compared to $333.4 million
in 2017 and $329.5 million in 2016. As a percentage of services revenue, cost of
services remained relatively flat at 71% in 2018, 69% in 2017 and 70% in 2016.
Cost of services as a percentage of services revenue is primarily reflective of
how our fixed cost structure is being absorbed by revenue.

Cost of Product Sales, excluding depreciation


Cost of product sales increased to $153.1 million in 2018 from $131.6 million in
2017 and $108.0 million in 2016. As a percentage of product sales revenue, cost
of sales improved to 72% for 2018 from 79% for 2017 and 89% for 2016. The
improvement in cost of product sales as a percentage of sales revenue in 2018
was primarily due to the improved absorption rates of our fixed costs and
investments in manufacturing automation.

General and Administrative Expense


General and administrative ("G&A") expenses include corporate management and
centralized administrative services that benefit our operations. G&A expenses
were $62.9 million in 2018 compared to $47.7 million and $39.4 million during
2017 and 2016, respectively. The variances are primarily due to changes in
compensation expense during those periods, including additional stock
compensation expense of $9.9 million in 2018 recorded for retirement eligible
employees. See Note 14 , Stock-Based Compensation for further detail.

Depreciation and Amortization Expense

Depreciation and amortization expense of $23.1 million in 2018 is down compared to $24.5 million in 2017 and $26.3 million in 2016.

Other (Income) Expense, net

The components of Other (income) expense, net, for the years ended December 31, 2018, 2017 and 2016 were as follows (in thousands):

                                                       2018        2017     

2016

Sale of assets                                      $ (1,078 )$ (346 )$ (618 )
Results of non-consolidated subsidiaries                (203 )     (332 )     (506 )
Foreign exchange                                       2,598        951      1,776
Rents and royalties                                     (510 )     (454 )     (420 )
Return on pension assets and other pension costs        (644 )     (587 )     (605 )
Acquisition-related costs                                623          -          -
Insurance settlement                                    (707 )        -          -
Severance, compensation and other charges                  -      1,145     

-

Other, net                                              (816 )      255        (27 )
Total Other (income) expense, net                   $   (737 )$  632

$ (400 )

In 2018, we received settlement of a claim for business interruption and damages incurred as a result of Hurricane Harvey in 2017.

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Foreign exchange gains and losses for the years ended December 31, 2018, 2017
and 2016 are summarized in the following table (in thousands):
(Gains) losses by currency     2018       2017       2016
   Angola Kwanza Spot        $   202$   (3 )$   408
   Australian Dollar             183        12         136
   British Pound                 158       (92 )       807
   Canadian Dollar               458       (62 )      (130 )
   Euro                          208     1,413         (49 )
   Indonesian Rupiah             297        80          29
   Mexican Peso                  141        23         (47 )
   Turkish Lira                  300        32          93
   Other currencies, net         651      (452 )       529
Total (gain) loss, net       $ 2,598$  951$ 1,776



Interest Expense

Interest expense increased by $2.6 million to $13.3 million in 2018 compared to
2017 primarily due to increased average borrowings on our revolving Credit
Facility which was used to fund an acquisition for $49.1 million in September
2018.

Income Tax Expense

Our effective tax rate was 24.2%, 18.4%, and 14.3% for 2018, 2017, and 2016,
respectively. Income tax expense of $25.4 million in 2018 increased by $7.2
million compared to $18.2 million in 2017 due to an increase in taxable income
in 2018, primarily in the United States. Income tax expense associated with
taxable income recognized in the United States increased by $4.9 million in 2018
compared to 2017. No other jurisdiction in which we operate had a material
change in income tax expense.

On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (the "TCJA") was signed
into law reducing the U.S. corporate income tax rate to 21%, effective January
1, 2018. During 2018, various proposed regulations have been released, providing
guidance on identified issues and topics regarding the TCJA. The most impactful
changes for the company from the TCJA are the deduction limitations for
compensation paid to executive officers and the benefit from the foreign derived
intangible income regime.

See Note 10, Income Taxes of the Notes to Consolidated Financial Statements for further detail of income tax expense.

Segment Analysis

The following charts and tables summarize the annual revenue and operating results for our two complementary business segments.














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                                Segment Revenue

                [[Image Removed: graph2018revenuebysegment.gif]]

Segment Revenue

                                        For the Years Ended December 31,

(dollars in thousands) 2018 % Change 2017 % Change

2016

Reservoir Description $ 413,082 (0.5 )% $ 415,220 (2.6 )% $ 426,205 Production Enhancement 287,764 23.7 % 232,599 41.8 %

     164,027
   Total Revenue          $ 700,846       8.2  %   $ 647,819       9.8  %   $ 590,232



Segment Operating Income
                                                       For the Years Ended December 31,
 (dollars in thousands)                    2018         % Change       2017       % Change       2016
Reservoir Description                $       54,847      (17.5 )%   $  66,500      (15.7 )%   $  78,881
Production Enhancement                       63,039       43.3  %      43,987      419.3  %       8,470
Corporate and other (1)                         736         NM           (519 )       NM            100
  Operating Income                   $      118,622        7.9  %   $ 

109,968 25.7 % $ 87,451

(1) "Corporate and other" represents those items that are not directly relating to a particular segment. "NM" means not meaningful.

Segment Operating Income Margins (1)

                               For the Years Ended December 31,
                            2018              2017            2016
                           Margin            Margin          Margin
Reservoir Description        13.3 %           16.0 %           18.5 %
Production Enhancement       21.9 %           18.9 %            5.2 %
  Total Company              16.9 %           17.0 %           14.8 %

(1) Calculated by dividing "Operating Income" by "Revenue."

Reservoir Description


Revenue for our Reservoir Description segment decreased slightly to $413.1
million in 2018 compared to $415.2 million in 2017 and $426.2 million in 2016.
The decreases in revenues in 2018 and 2017 as compared to each corresponding
prior year were primarily due to the reduced international and deepwater project
activity levels during 2017 and 2018. This segment's operations continue to work
on large-scale, long-term, crude-oil and LNG projects with an emphasis on
producing fields located in offshore developments and international markets. We
continue to focus on large-scale core analyses and reservoir fluids
characterization studies in the Asia-Pacific areas, offshore Europe and Africa,
offshore South America, North America, and the Middle East.


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Operating income decreased to $54.8 million in 2018 from $66.5 million in 2017
due to lower activity levels derived from large capital spending projects in
international markets and additional stock compensation expense of $6.3 million
in 2018 for retirement eligible employees. See Note 14 , Stock-Based
Compensation for further detail. Operating income decreased to $66.5 million in
2017 from $78.9 million in 2016, primarily due to lower activity levels.
Operating margins, excluding the additional stock compensation expense recorded
in 2018 were comparable at 15% in 2018 and 16.0% in 2017 but down from 18.5% in
2016.

Production Enhancement

Revenue for our Production Enhancement segment increased to $287.8 million in
2018 compared to $232.6 million in 2017 and $164.0 million in 2016. The increase
in onshore North America industry activity during 2018 and 2017 compared to each
corresponding prior year resulted in increased demand for our products
associated with land-based completion of oil wells in U.S. unconventional
developments.

Operating income for this segment increased to $63.0 million in 2018 from $44.0
million in 2017 primarily due to increased demand for our higher margin products
and services and the impact of higher revenue on our fixed-cost structure offset
by additional stock compensation expense of $3.7 million in 2018 for retirement
eligible employees. See Note 14 , Stock-Based Compensation for further detail.
Operating income for this segment increased to $44.0 million in 2017 from $8.5
million in 2016 primarily due to increased demand for our higher margin products
and services and the impact of higher revenue on our fixed-cost structure.
Operating margins were 21.9% in 2018 up from 18.9% in 2017 and 5.2% in 2016.

Liquidity and Capital Resources

General


We have historically financed our activities through cash on hand, cash flows
from operations, bank credit facilities, equity financing and the issuance of
debt. Cash flows from operating activities provide the primary source of funds
to finance operating needs, capital expenditures and our dividend and share
repurchase programs. If necessary, we supplement this cash flow with borrowings
under bank credit facilities to finance some capital expenditures and business
acquisitions. As we are a Netherlands holding company, we conduct substantially
all of our operations through subsidiaries. Our cash availability is largely
dependent upon the ability of our subsidiaries to pay cash dividends or
otherwise distribute or advance funds to us and on the terms and conditions of
our existing and future credit arrangements. There are no restrictions
preventing any of our subsidiaries from repatriating earnings, and there are no
restrictions or income taxes associated with distributing cash to the parent
company through loans or advances. As of December 31, 2018, $12.6 million of our
$13.1 million of cash was held by our foreign subsidiaries, including the U.S.

Our financial statements are prepared in conformity with generally accepted
accounting principles in the U.S. ("U.S. GAAP" or "GAAP"). We utilize the
non-GAAP financial measure of free cash flow to evaluate our cash flows and
results of operations. Free cash flow is defined as net cash provided by
operating activities (which is the most directly comparable GAAP measure) less
cash paid for capital expenditures. Management believes that free cash flow
provides useful information to investors regarding the cash that was available
in the period that was in excess of our needs to fund our capital expenditures
and operating activities. Free cash flow is not a measure of operating
performance under GAAP, and should not be considered in isolation nor construed
as an alternative to operating profit, net income (loss) or cash flows from
operating, investing or financing activities, each as determined in accordance
with GAAP. Free cash flow does not represent residual cash available for
distribution because we may have other non-discretionary expenditures that are
not deducted from the measure. Moreover, since free cash flow is not a measure
determined in accordance with GAAP and thus is susceptible to varying
interpretations and calculations, free cash flow, as presented, may not be
comparable to similarly titled measures presented by other companies. The
following table reconciles this non-GAAP financial measure to the most directly
comparable measure calculated and presented in accordance with U.S. GAAP for the
years ended December 31, 2018, 2017 and 2016 (in thousands):
                                               For the Years Ended December 

31,

Free Cash Flow Calculation                     2018           2017          

2016

Net cash provided by operating activities $   111,827$ 124,271$ 131,887
Less: cash paid for capital expenditures      (21,741 )      (18,775 )     (11,356 )
Free cash flow                            $    90,086$ 105,496$ 120,531




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Free cash flow as a percent of income from continuing operations of 113.3%
continued to be strong in 2018. The decrease in free cash flow in 2018 compared
to 2017 was primarily due to increases in both working capital and capital
expenditures in 2018 as the activity levels in the oil industry improved. The
decrease in free cash flow in 2017 compared to 2016 was primarily due to
increases in both working capital and capital expenditures in 2017 as the
activity levels in the oil industry improved.

Cash Flows

The following table summarizes cash flows for the years ended December 31, 2018, 2017 and 2016 (in thousands):

                                           2018          2017          2016
Cash provided by/(used in):
Operating activities                    $ 111,827$ 124,271$ 131,887
Investing activities                      (70,639 )     (20,557 )     (14,721 )
Financing activities                      (42,472 )    (104,078 )   

(124,896 ) Net change in cash and cash equivalents $ (1,284 )$ (364 )$ (7,730 )




The decreases in cash provided by operating activities in 2018 compared to 2017
and 2017 compared to 2016 was primarily due to increases in working capital and
changes in net income as the activity levels in the oil industry improved.
Working capital was impacted by the increase in inventories during 2018 which
was due to more raw materials and finished goods being held in our distribution
network to support the anticipated growth in product sales.

Cash used in investing activities in 2018 increased $50.1 million compared to
2017 primarily as a result of an acquisition for $49.1 million in 2018 as well
as increased capital expenditures in 2018 as activity levels in the oil industry
improved. Cash used in investing activities in 2017 increased $5.8 million
compared to 2016 primarily as a result of increased capital expenditures.

Cash used in financing activities in 2018 decreased $61.6 million compared to
2017. Cash used in financing activities in 2017 decreased $20.8 million compared
to 2016. During 2018, we used $7.5 million to repurchase our common shares,
$97.3 million to pay dividends, and increased our debt balance by $64 million.
During 2017, we used $16.9 million to repurchase our common shares, $97.1
million to pay dividends, and increased our debt balance by $10 million. During
2016, we used $7.2 million to repurchase our common shares, $95.1 million to pay
dividends, and decreased our debt balance by $215 million through the issuance
of new shares.

During the year ended December 31, 2018, we repurchased 85,985 shares of our
common stock for an aggregate amount of $7.5 million, or an average price of
$86.66 per share. The repurchase of shares in the open market is at the
discretion of management pursuant to shareholder authorization. We regard these
treasury shares as a temporary investment which may be used to fund restricted
shares that vest or to finance future acquisitions. Under Dutch law and subject
to certain Dutch statutory provisions and shareholder approval, we can hold a
maximum of 50% of our issued shares in treasury. We currently have shareholder
approval to hold 10% of our issued share capital in treasury. On May 24, 2018 at
our annual shareholders meeting, our shareholders authorized the extension of
our share repurchase program until November 24, 2019 to purchase up to 10% of
our issued share capital. We believe this share repurchase program has been
beneficial to our shareholders. Our share price has increased from $4.03 per
share in 2002, when we began to repurchase shares, to $59.66 per share on
December 31, 2018, an increase of over 1,380%.

Credit Facility and Available Future Liquidity


In 2011, we issued two series of senior notes with an aggregate principal amount
of $150 million ("Senior Notes") in a private placement transaction. Series A
consists of $75 million in aggregate principal amount of notes that bear
interest at a fixed rate of 4.01% and are due in full on September 30, 2021.
Series B consists of $75 million in aggregate principal amount of notes that
bear interest at a fixed rate of 4.11% and are due in full on September 30,
2023. Interest on each series of the Senior Notes is payable semi-annually on
March 30 and September 30.

On June 18, 2018, we entered into an agreement to amend our revolving credit
facility ("Credit Facility"). To appropriately size the facility, the aggregate
borrowing commitment was reduced from $400 million to $300 million. The Credit
Facility provides an option to increase the commitment under the Credit Facility
by an additional $100 million to bring the total borrowings available to $400
million if certain prescribed conditions are met by the Company. The Credit
Facility bears interest at variable rates from LIBOR plus 1.375% to a maximum of
LIBOR plus 2.0%.


                                       25
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Any outstanding balance under the Credit Facility is due June 19, 2023, when the
Credit Facility matures. Interest payment terms are variable depending upon the
specific type of borrowing under this facility. Our available capacity at any
point in time is subject to all terms of the agreements, and is reduced by
borrowings outstanding at the time and outstanding letters of credit which
totaled $18.0 million at December 31, 2018, resulting in an available borrowing
capacity under the Credit Facility of $140.0 million. In addition to those items
under the Credit Facility, we had $13.3 million of outstanding letters of credit
and performance guarantees and bonds from other sources as of December 31, 2018.

The terms of the Credit Facility and Senior Notes require us to meet certain
covenants, including, but not limited to, an interest coverage ratio
(consolidated EBITDA divided by interest expense) and a leverage ratio
(consolidated net indebtedness divided by consolidated EBITDA), where
consolidated EBITDA (as defined in each agreement) and interest expense are
calculated using the most recent four fiscal quarters. The Credit Facility has
the more restrictive covenants with a minimum interest coverage ratio of 3.0 to
1.0 and a maximum leverage ratio of 2.5 to 1.0. We believe that we are in
compliance with all such covenants contained in our credit agreements. Certain
of our material, wholly-owned subsidiaries are guarantors or co-borrowers under
the Credit Facility and Senior Notes.

In 2014, we entered into two interest rate swap agreements for a total notional
amount of $50 million to hedge changes in the variable rate interest expense on
$50 million of our existing or replacement LIBOR-priced debt. Under the first
swap agreement of $25 million, we fixed the LIBOR portion of the interest rate
at 1.73% through August 29, 2019, and under the second swap agreement of $25
million, we fixed the LIBOR portion of the interest rate at 2.50% through
August 29, 2024. Each swap is measured at fair value and recorded in our
consolidated balance sheet as an asset or liability. They are designated and
qualify as cash flow hedging instruments and are highly effective. Unrealized
gains and losses are deferred to shareholders' equity as a component of
accumulated other comprehensive income (loss) and are recognized in income as an
increase or decrease to interest expense in the period in which the related cash
flows being hedged are recognized in expense.

In addition to our repayment commitments under our Credit Facility and our Senior Notes, we have non-cancellable operating lease arrangements under which we lease property including land, buildings, office equipment and vehicles.

The following table summarizes our future contractual obligations under these arrangements (in thousands):

                                               Less than 1                                     More than
                                  Total            year         1-3 Years      3-5 Years        5 Years
Contractual Obligations:
Debt (1)                      $    292,000     $        -     $    75,000$  217,000     $         -
Operating leases                    66,322         16,267          22,346         12,894          14,815
Pension (2)                            800            800               -              -               -
  Total contractual
obligations                   $    359,122$   17,067$    97,346$  229,894$    14,815

(1) Not included in the above balances are anticipated cash payments for interest of $6.1 million a year
for 2019-2021 and cash payments for interest of $3.1 million a year for 2022-2023 for a total of $24.5
million.
(2) Our Dutch pension plan requires annual employer contributions. Amounts payable in the future will be
based on future workforce factors which cannot be projected beyond one year.



We have no significant purchase commitments or similar obligations outstanding
at December 31, 2018. Not included in the table above are uncertain tax
positions of $7.5 million that we have accrued for at December 31, 2018, as the
amounts and timing of payment, if any, are uncertain. See Note 10 of the Notes
to Consolidated Financial Statements for further detail of this amount.

At December 31, 2018, we had tax net operating loss carry-forwards in various
jurisdictions of $25.8 million. Although we cannot be certain that these
operating loss carry-forwards will be utilized, we anticipate that we will have
sufficient taxable income in future years to allow us to fully utilize the
carry-forwards that are not subject to a valuation allowance as of December 31,
2018. If unused, those carry-forwards which are subject to expiration may expire
during the years 2018-2028. During 2018, less than $0.1 million of net operating
loss carry-forwards which carried a full valuation allowance expired unused.

We expect our investment in capital expenditures to track client demand for our
services and products. Given the improving, but still uncertain, trend in
industry activity levels, we have not determined, at this time, the level of
investment that will be made in 2019. We will, however, continue to invest to
fund the purchase of instrumentation, tools and equipment along with
expenditures to replace obsolete or worn-out instrumentation, tools and
equipment, to consolidate certain facilities to gain operational efficiencies,
and to increase our presence where requested by our clients. In addition, we
plan to continue to (i)

                                       26
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repurchase our common shares on the open market through our share repurchase
program, (ii) pay a dividend and (iii) if available, in the market at acceptable
valuations, acquire complementary technologies. Our ability to continue these
initiatives depends on, among other things, market conditions and our ability to
generate free cash flow.

Our ability to maintain and increase our operating income and cash flows is
largely dependent upon continued investing activities. We are a Netherlands
holding company and substantially all of our operations are conducted through
subsidiaries. Consequently, our cash flow depends upon the ability of our
subsidiaries to pay cash dividends or otherwise distribute or advance funds to
us. We believe our future cash flows from operating activities, supplemented by
our borrowing capacity under existing facilities and our ability to issue
additional equity should be sufficient to meet our contractual obligations,
capital expenditures, working capital needs, dividend payments, debt
requirements and to finance future acquisitions.

Outlook

As part of our long-term growth strategy, we continue our efforts to expand our market presence by opening or expanding facilities in strategic areas and realizing synergies within our business lines subject to client demand and market conditions. We believe our market presence provides us a unique opportunity to service clients who have global operations whether they are international oil companies, national oil companies, or independent oil companies.


We are encouraged by the increased focus of our major clients regarding capital
management, return on invested capital ("ROIC"), free cash flow, and returning
capital back to their shareholders, as opposed to a focus on production growth
at any cost. The companies adopting value versus volume metrics tend to be the
more technologically sophisticated operators and form the foundation of Core
Lab's worldwide client base. We expect to benefit from our clients' shift in
focus from strictly production growth to employing higher technological
solutions in their efforts to maximize economic production growth and estimated
ultimate recovery ("EUR").

During the fourth quarter 2018, the worldwide crude-oil market added supply,
likely in anticipation of the proposed Iran sanctions. Consequently, during
November and December the per-barrel price of crude oil fell by more than 40%
from the year's peak in October 2018. However, global crude-oil inventories
exited 2018 at approximately 38 days of consumption, consistent with a
multi-year trend of declining global crude-oil inventories related to demand.
The International Energy Agency's ("IEA") most recent estimated worldwide demand
projections remain strong with 1,400,000 additional barrels of oil per day
needed in 2019.

After five years of muted investment in international, offshore and deepwater
projects, oil companies announced more than 30 FIDs in 2018, an increase of more
than 20% from 2017. The renewed investment at a global level is critical in
order to meet future supply needs. Recognition of the need for investment is
evidenced by the FIDs announced over the last two years and Wood McKenzie's
estimation of another 30 upstream projects for 2019. However, Core Lab
anticipates a slowing in further project announcements until confidence in the
balance of global crude-oil markets is restored. We believe there will be a
positive correction to the temporary oversupply of crude oil by the end of the
first quarter 2019, which should encourage additional FID projects to be
announced in 2019.

We continue to focus on large-scale core analyses and reservoir fluid
characterization studies in the Eagle Ford, the Permian Basin, offshore Alaska
and the Gulf of Mexico, along with Guyana, Malaysia and other international
locations such as offshore South America, and the Middle East. We also focus on
complex completions in unconventional tight-oil reservoirs, technological
solutions and services for increasing daily productions and EURs.

As customary, Core Lab expects typical sequential seasonal industry patterns
will cause the first quarter of 2019 to be down, and international field
development spending will be funded largely from operating budgets.
International recovery on a more broad-based scope is expected to improve as
2019 unfolds. Reservoir Description continues to discuss international projects
with clients, which are in alignment with FIDs previously announced. The revenue
opportunity for Reservoir Description occurs once the well has been drilled and
core and fluid samples are taken and analyzed. Activity levels and revenue
opportunities from these FIDs and the emerging international recovery are
expected to have a positive impact on financial performance in 2019.

The average first quarter 2019 U.S. rig count is projected to be flat to
modestly down sequentially, with U.S. completion activity to remain at similar
levels exiting 2018, until transitory logistical bottlenecks are addressed (e.g.
supply chain logistics and take-away restrictions are resolved in the Permian
Basin of West Texas). These logistical bottlenecks are anticipated to be
resolved in the second half of 2019. In addition, an emerging trend to larger
pad drilling sites, increasing from six to eight wells up to 24 wells, will
create an increase in drilled but uncompleted wells over the next several
quarters. Combined, these issues could impact the rate of revenue growth
opportunity for any company that is reliant on completions as a catalyst for
growth.

                                       27
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The drilled-but-uncompleted well inventory levels continue to rise and are in excess of moderated inventory levels for current activity levels. These uncompleted wells should provide Core Lab with future revenue opportunities.


Reservoir Description continues to discuss international projects with clients
which are in alignment with FIDs previously announced. Activity levels and
revenue opportunities from FIDs and the emerging international recovery are
expected to have a positive impact on financial performance in 2019. The revenue
opportunity for Reservoir Description occurs once the well has been drilled and
core and fluid samples are taken and analyzed.


Critical Accounting Estimates


The preparation of financial statements in accordance with U.S. GAAP requires us
to make certain estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of assets and liabilities at the date of
the financial statements and the reported amounts of revenue and expenses during
the reporting period. We evaluate our estimates on an ongoing basis and
determine the adequacy of our estimates based on our historical experience and
various other assumptions that we believe are reasonable under the
circumstances. By nature, these judgments are subject to an inherent degree of
uncertainty. We consider an accounting estimate to be critical if it is highly
subjective and if changes in the estimate under different assumptions would
result in a material impact on our financial condition and results of
operations. The following transaction types require significant judgment and,
therefore, are considered critical accounting policies as of December 31, 2018.

Income Taxes


Our income tax expense includes income taxes of the Netherlands, the U.S. and
other foreign countries as well as local, state and provincial income taxes. We
recognize deferred tax assets or liabilities for the differences between the
financial statement carrying amount and tax basis of assets and liabilities
using enacted tax rates in effect for the years in which the asset is recovered
or the liability is settled. We estimate the likelihood of the recoverability of
our deferred tax assets (particularly, net operating loss carry-forwards). Any
valuation allowance recorded is based on estimates and assumptions of taxable
income into the future and a determination is made of the magnitude of deferred
tax assets which are more likely than not to be realized. Valuation allowances
of our net deferred tax assets aggregated to $9.7 million and $8.2 million at
December 31, 2018 and 2017, respectively. If these estimates and related
assumptions change in the future, we may be required to record additional
valuation allowances against our deferred tax assets and our effective tax rate
may increase which could result in a material adverse effect on our financial
position, results of operations and cash flows. We have not provided for
deferred taxes on the unremitted earnings of certain subsidiaries that we
consider to be indefinitely reinvested. Should we make a distribution of the
unremitted earnings of these subsidiaries, we may be required to record
additional taxes. We record a liability for unrecognized tax benefits resulting
from uncertain tax positions taken or expected to be taken in our tax return. We
also recognize interest and penalties, if any, related to unrecognized tax
benefits in income tax expense.

Long-Lived Assets, Intangibles and Goodwill


Property, plant and equipment are carried at cost less accumulated depreciation.
Major renewals and improvements are capitalized while maintenance and repair
costs are charged to expense as incurred. They are depreciated using the
straight-line method based on their individual estimated useful lives, except
for leasehold improvements, which are depreciated over the remaining lease term,
if shorter. We estimate the useful lives and salvage values of our assets based
on historical data of similar assets. When long-lived assets are sold or
retired, the remaining costs and related accumulated depreciation are removed
from the accounts and any resulting gain or loss is included in income. These
capitalized long-lived assets could become impaired if our operating plans or
business environment changes.

Intangible assets, including patents, trademarks, and trade names, are carried
at cost less accumulated amortization. Intangibles with determinable lives are
amortized using the straight-line method based on the estimated useful life of
the intangible. Intangibles with indeterminable lives, which consist primarily
of corporate trade names, are not amortized, but are tested for impairment
annually or whenever events or changes in circumstances indicate that impairment
is possible.

We review our long-lived assets, including definite-lived intangible assets, for
impairment when events or changes in circumstances indicate that their net book
value may not be recovered over their remaining service lives. Indicators of
possible impairment may include significant declines in activity levels in
regions where specific assets or groups of assets are located, extended periods
of idle use, declining revenue or cash flow or overall changes in general market
conditions.


                                       28
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Whenever possible impairment is indicated, we compare the carrying value of the
assets to the sum of the estimated undiscounted future cash flows expected from
use, plus salvage value, less the costs of the subsequent disposition of the
assets. If impairment is still indicated, we compare the fair value of the
assets to the carrying amount, and recognize an impairment loss for the amount
by which the carrying value exceeds the fair value. We did not record any
material impairment charges relating to our long-lived assets held for use
during the years ended December 31, 2018, 2017 and 2016.

We record goodwill as the excess of the purchase price over the fair value of
the net assets acquired in acquisitions accounted for under the purchase method
of accounting. We test goodwill for impairment annually, or more frequently if
circumstances indicate a possible impairment.

We evaluated our goodwill for impairment by comparing the fair value of each of
our reporting units, which are our reportable segments, to their net carrying
value as of the balance sheet date. We estimated the fair value of each
reporting unit using a discounted future cash flow analysis. Estimated future
cash flows were based on the company's best estimate of future performance. Our
impairment analysis is quantitative; however, it includes subjective estimates
based on assumptions regarding future growth rates, interest rates and operating
expenses. If the carrying value of the reporting unit exceeds the fair value
determined, an impairment loss is recorded to the extent that the implied fair
value of the goodwill of the reporting unit is less than its carrying value. We
did not record impairment charges relating to our goodwill or our
indefinite-lived intangible assets during the years ended December 31, 2018,
2017 and 2016.

We have never identified nor recorded any impairments relating to the goodwill of our current continuing operations.

Pensions and Other Postretirement Benefits


We maintain a noncontributory defined benefit pension plan for substantially all
of our Dutch employees hired before 2000. We utilize an actuary to assist in
determining the value of the projected benefit obligation. This valuation
requires various estimates and assumptions concerning mortality, future pay
increases, expected return on plan assets and discount rate used to value our
obligations. We recognize net periodic benefit cost based upon these estimates.
As required by current accounting standards, we recognize net periodic pension
costs associated with this plan in income from current operations and recognize
the unfunded status of the plan, if any, as a long-term liability. In addition,
we recognize as a component of other comprehensive income, the gains or losses
and prior service costs or credits that arise during the period but are not
recognized as components of net periodic pension cost. See Note 11 of the Notes
to Consolidated Financial Statements. Furthermore, we sponsor several defined
contribution plans for the benefit of our employees. We expense these
contributions in the period the contribution is made.

Stock-Based Compensation


We have two stock-based compensation plans, as described in further detail in
Note 14 of the Notes to Consolidated Financial Statements. We evaluate the
probability that certain of our stock-based plans will meet targets established
within the respective agreements and result in the vesting of such awards. For
new awards issued and awards modified, repurchased or canceled, the compensation
expense is equal to the fair value of the award at the date of the grant and is
recognized in the Consolidated Statements of Operations for those awards over
the requisite service period of the award. The fair value is determined by
calculating the share price on the date of grant less the discounted value of
the expected dividends to be paid over the vesting period.

Off-Balance Sheet Arrangements

Other than normal operating leases, we do not have any off-balance sheet financing arrangements such as securitization agreements, liquidity trust vehicles, synthetic leases or special purpose entities. As such, we are not materially exposed to any financing, liquidity, market or credit risk that could arise if we had engaged in such financing arrangements.

Forward-Looking Statements


This Form 10-K and the documents incorporated in this Form 10-K by reference
contain forward-looking statements within the meaning of Section 27A of the
Securities Act of 1933 and Section 21E of the Exchange Act. These
"forward-looking statements" are based on an analysis of currently available
competitive, financial and economic data and our operating plans. They are
inherently uncertain and investors should recognize that events and actual
results could turn out to be significantly different from our expectations. By
way of illustration, when used in this document, words such as "anticipate",
"believe", "expect", "intend", "estimate", "project", "will", "should", "could",
"may", "predict" and similar expressions are intended to identify
forward-looking statements. You are cautioned that actual results could differ
materially from those anticipated in

                                       29
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forward-looking statements. Any forward-looking statements, including statements
regarding the intent, belief or current expectations of us or our management,
are not guarantees of future performance and involve risks, uncertainties and
assumptions about us and the industry in which we operate, including, among
other things:
• our ability to continue to develop or acquire new and useful technology;


•      the realization of anticipated synergies from acquired businesses and
       future acquisitions;

• our dependence on one industry, oil and gas, and the impact of commodity

prices on the expenditure levels of our clients;

• competition in the markets we serve;

• the risks and uncertainties attendant to adverse industry, political,

       economic and financial market conditions, including stock prices,
       government regulations, interest rates and credit availability;

• unsettled political conditions, war, civil unrest, currency controls and

governmental actions in the numerous countries in which we operate;

• changes in the price of oil and natural gas;

• weather and seasonal factors;

• integration of acquired businesses; and

• the effects of industry consolidation.




Our businesses depend, to a large degree, on the level of spending by oil and
gas companies for exploration, development and production activities. Therefore,
a sustained increase or decrease in the price of natural gas or oil, which could
have a material impact on exploration, development and production activities,
could also materially affect our financial position, results of operations and
cash flows.

The above description of risks and uncertainties is by no means all-inclusive,
but is designed to highlight what we believe are important factors to consider.
For a more detailed description of risk factors, please see "Item 1A. Risk
Factors" in this Form 10-K and our reports and registration statements filed
from time to time with the SEC.

All forward-looking statements in this Form 10-K are based on information
available to us on the date of this Form 10-K. We do not intend to update or
revise any forward-looking statements that we may make in this Form 10-K or
other documents, reports, filings or press releases, whether as a result of new
information, future events or otherwise, unless required by law.

Recent Accounting Pronouncements

Pronouncements Adopted in 2018


In May 2014, the FASB issued ASU 2014-09 ("Revenue from Contracts with
Customers"), which provides guidance on revenue recognition. The core principle
of this guidance is that an entity should recognize revenue to depict the
transfer of promised goods or services to customers in an amount that reflects
the consideration to which the entity expects to be entitled in exchange for
those goods or services. This guidance requires entities to apply a five-step
method to (1) identify the contract(s) with customers; (2) identify the
performance obligation(s) in the contract; (3) determine the transaction price;
(4) allocate the transaction price to the performance obligation(s) in the
contract; and (5) recognize revenue when (or as) the entity satisfies a
performance obligation. We adopted this standard and related amendments on
January 1, 2018. The adoption of this standard did not result in any material
changes to our revenue recognition policies and procedures nor to our financial
statements. Upon adoption, we used the modified retrospective approach; this
approach resulted in no cumulative adjustment to retained earnings or net income
and no adjustments to prior periods.

In March 2017, the FASB issued ASU 2017-07 ("Improving the Presentation of Net
Periodic Pension Cost and Net Periodic Postretirement Benefit Cost"), which
requires that an employer report the service cost component in the same line
item as other compensation costs arising from services rendered by the pertinent
employees during the period. The other components of net benefit cost are
required to be presented in the income statement separately from the service
cost component and outside a subtotal of income from operations. We adopted this
standard on January 1, 2018. We used the practical expedient method which allows
us to use the amounts disclosed in our pension footnote for the year ended
December 31, 2017 as the estimation basis for applying the retrospective
presentation requirement. The adoption of this standard did not result in any
material changes to our consolidated financial statements.


                                       30
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Pronouncements Not Yet Effective


In February 2016, the FASB issued ASU 2016-02 ("Leases"), which introduces the
recognition of lease assets and lease liabilities by lessees for those leases
classified as operating leases under previous guidance. The new standard
establishes a right-of-use ("ROU") model that requires a lessee to record an ROU
asset and a lease liability on the balance sheet for all leases with terms
longer than 12 months. The new standard is effective for fiscal years beginning
after December 15, 2018 and interim periods within those fiscal years with early
adoption permitted. In July 2018, the FASB issued ASU 2018-11 ("Targeted
Improvements to Leases"), which provides companies with an additional transition
method that allows the effects of the adoption of the new standard to be
recognized as a cumulative-effect adjustment to the opening balance of retained
earnings in the period of adoption. We have evaluated and elected this optional
transition method for adoption. Based on our current lease portfolio, we
estimate that the adoption of this standard will result in approximately $77
million of additional assets and liabilities being reflected on our Consolidated
Balance Sheets upon adoption of this standard on January 1, 2019; however, there
will not be a material impact to our Consolidated Statement of Operations or
Cash Flows.

In June 2016, the FASB issued ASU 2016-13 ("Measurement of Credit Losses on
Financial Instruments") which replaces the incurred loss impairment methodology
in current GAAP with a methodology that reflects expected credit losses and
requires consideration of a broader range of reasonable and supportable
information to inform credit loss estimates. The new standard is effective for
fiscal years beginning after December 15, 2019, including interim periods within
those fiscal years with early adoption permitted in fiscal years beginning after
December 15, 2018, including interim periods within those fiscal years. We are
evaluating the impact that the adoption of this standard will have on our
consolidated financial statements.

In February 2018, the FASB issued ASU 2018-02 ("Reclassification of Certain Tax
Effects from Accumulated Other Comprehensive Income"), which provides companies
with an option to reclassify stranded tax effects resulting from enactment of
the Tax Cuts and Jobs Act (the "TCJA") from accumulated other comprehensive
income to retained earnings. The new standard is effective for fiscal years
beginning after December 15, 2018, and interim periods within those fiscal years
with early adoption permitted, and would be applied either in the period of
adoption or retrospectively to each period (or periods) in which the effect of
the change in the tax rate as a result of the TCJA is recognized. We do not
expect the adoption of this standard to have a material impact on our
consolidated financial statements.

© Edgar Online, source Glimpses

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