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MarketScreener Homepage  >  Equities  >  Nasdaq  >  Noble Energy    NBL

NOBLE ENERGY

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NOBLE ENERGY : Management's Discussion and Analysis of Financial Condition and Results of Operations (form 10-Q)

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11/07/2019 | 12:22pm EST
Management's Discussion and Analysis of Financial Condition and Results of
Operations (MD&A) is intended to provide a narrative about our business from the
perspective of management. We use common industry terms, such as thousand
barrels of oil equivalent per day (MBoe/d) and million cubic feet equivalent per
day (MMcfe/d), to discuss production and sales volumes. Our MD&A is presented in
the following major sections:
•   Executive Overview  ;


•   Operating Outlook  ;


•   Results of Operations - Exploration and Production  ;


•   Results of Operations - Midstream  ;


•   Results of Operations - Corporate  ; and


•   Liquidity and Capital Resources  .


The preceding consolidated financial statements, including the notes thereto,
contain detailed information that should be read in conjunction with our MD&A.
EXECUTIVE OVERVIEW
The following discussion highlights significant operating and financial results
for third quarter 2019. This discussion should be read in conjunction with our
Annual Report on Form 10-K for the year ended December 31, 2018, which includes
disclosures regarding our critical accounting policies as part of "Management's
Discussion and Analysis of Financial Condition and Results of Operations."
Operational Environment Update
Recent Activities During third quarter 2019, we progressed our US onshore
drilling and completions activities, advanced our Eastern Mediterranean and West
Africa regional natural gas developments and continued advancement of our US
onshore and international exploration opportunities. We continue to execute
capital and operating cost reduction efforts and reduce cycle times through
operational improvements. During the quarter, we delivered consolidated sales
volumes of 379 MBoe/d and achieved quarterly sales volumes records in both the
DJ and Delaware Basins. This increased production was achieved with reduced
capital investment. We continue to focus on progressing the Leviathan natural
gas project, which was over 90% complete at quarter-end. Our focus on cost and
capital efficiency and the startup of the Leviathan natural gas project should
provide sustainable cash flows beginning in 2020.
Commodity Prices Crude oil prices remained volatile during third quarter 2019,
with Brent and WTI averaging approximately $61 and $56 per barrel, respectively.
The outlook for fourth quarter 2019 will depend on competing factors for supply
and demand. Production cuts by the Organization of Petroleum Exporting Countries
and geopolitical factors in critical oil producing regions remain constructive
for global oil prices. However, a weakening of crude oil demand amid signs of a
potential softening

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in the global economy could result in lower prices. In addition, US and China
trade tensions threaten further damage to global trade and economic growth and,
consequently, crude oil demand. In the Delaware Basin, new pipeline startups,
including interim crude oil service on the EPIC Y-Grade pipeline, have begun to
improve basis differentials, while planned expansion of export infrastructure
should help alleviate a portion of the discount of WTI to Brent going forward.
The US natural gas market continues to see depressed levels as supply outpaced
demand over the past year. Despite record domestic liquefied natural gas (LNG)
exports and high natural gas fired electric generation, natural gas inventories
are projected to remain at or slightly above historical five-year averages.
Natural gas price differentials increased in the DJ Basin, while differentials
in the Delaware Basin continue to be wide despite additional pipeline capacity
from the Delaware Basin to Corpus Christi, Texas. Additional Delaware Basin
natural gas pipeline expansions are targeted for in-service in late 2020.
NGL prices are also suppressed amid increased production, high inventory levels,
and downstream fractionation and export bottlenecks. US NGL prices should
strengthen as new processing and export facilities are brought online.
To mitigate the effect of commodity price volatility, we have entered into crude
oil and natural gas price hedging arrangements which also serve to enhance the
predictability of our cash flows.
Financial Initiatives
Financial Flexibility, Liquidity and Balance Sheet Strength As we progress
through the remainder of 2019, we believe we are positioned for sustainability,
operational efficiency, and long-term success throughout the oil and gas
business cycle. We remain committed to maintaining capital discipline and
financial strength. See   Operating Outlook - 2019 Capital Investment Program  .
If commodity prices decline or operating costs rise, we could experience
material asset impairments, as well as material negative impacts on our
revenues, profitability, cash flows, liquidity and proved reserves, and, in
response, we may consider changes in our capital program, share repurchase
program, dividends policy or operating cost structure, and/or potential asset
sales. Our revenues and our stock price could decline as a result of these
potential developments.
Recently Issued Accounting Standards
See   Item 1. Financial Statements - Note   2. Basis of Presentation.
OPERATING OUTLOOK
2019 Organic Capital Investment Program  Our initial 2019 organic capital
program, which excludes capital funded by Noble Midstream Partners and
acquisition capital related to the EMG Pipeline, ranged from $2.4 to $2.6
billion and was primarily allocated to US onshore development and completion of
the Leviathan natural gas project. In second quarter 2019, we lowered our full
year organic capital program by $100 million. In third quarter 2019, as a result
of US onshore well cost reductions and the Leviathan project spending below
budget, we lowered our full year organic capital program by an additional $100
million. Fourth quarter 2019 expected organic capital expenditures range from
$425 to $475 million and will primarily be allocated to continued US onshore
development and completion of the Leviathan natural gas project. Amounts exclude
capital funded by Noble Midstream Partners and acquisition capital related to
the EMG Pipeline. See   Liquidity and Capital Resources  .
Dividends In April, July and October 2019, our Board of Directors approved
quarterly cash dividends in amounts that represented a 9% increase over the
prior year. This is our second straight year to increase our dividend,
reflecting our commitment to return value to shareholders.
Colorado Senate Bill 19-181 For some time, initiatives have been underway in the
State of Colorado to limit or ban crude oil and natural gas exploration,
development or operations. During first quarter 2019, Senate Bill 19-181 (SB
181) was passed by the State Legislature. On April 16, 2019, the Governor signed
the bill into law. The legislation makes changes in Colorado oil and gas law,
including, among other matters, requiring the Colorado Oil and Gas Conservation
Commission (Commission) to prioritize public health and environmental concerns
in its decisions, instructing the Commission to adopt rules to minimize
emissions of methane and other air contaminants, and delegating considerable new
authority to local governments to regulate surface impacts. The Commission has
initiated new rulemakings related to, among other things, incorporating new
public health, safety, and environmental priorities into their regulations,
updating wellbore integrity and flowline rules, and adopting new alternative
location analysis and cumulative impact procedures. In addition, some local
communities have adopted further restrictions for oil and gas activities, such
as requiring greater setbacks, and other groups have sought a cessation of
permit issuances entirely until the Commission publishes new rules in keeping
with SB 181.
The majority of our acreage in Colorado is in rural, unincorporated areas of
Weld County, and we continue to work closely with local regulators and
communities to ensure safe and responsible operations and future planning. At
this time, we do not foresee significant changes to our development plans, as we
have all necessary approvals of more than 550 permits to drill wells over the
next several years. The approved permits are for wells in multiple Integrated
Development Plans (IDPs), many of which are

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in our Mustang Comprehensive Drilling Plan (CDP). We will continue to work
closely with Weld County on the required local permits and agreements for the
CDP.  However, if additional regulatory measures are adopted, we could incur
additional costs to comply with the requirements or we may experience delays
and/or curtailment in the permitting or pursuit of our exploration, development,
or production activities. Such compliance costs and delays, curtailments,
limitations, or prohibitions could have a material adverse effect on our cash
flows, results of operations, financial condition, and liquidity.
RESULTS OF OPERATIONS - EXPLORATION AND PRODUCTION (E&P)
We continue to advance our major development projects, which we expect to
deliver incremental production and cash flows over the next several years.
Sanctioned Ongoing Development Projects
A "sanctioned" development project is one for which a final investment decision
has been reached. Updates on major development projects are as follows:
US Onshore
During third quarter 2019, our US onshore E&P activities consisted of the
following:
                                                                             Average
                                     Average                     Wells        Sales
                                       Rigs         Wells       Brought      Volumes
Location                             Operated    Drilled (1)     Online      (MBoe/d)
DJ Basin                                2            28            38          158
Delaware Basin                          3            20            17           70
Eagle Ford Shale                        -             -            -            65
Total                                   5            48            55          293


(1)  The number of wells drilled refers to the number of wells completed,
     regardless of when drilling was initiated.


DJ Basin  During third quarter 2019, we achieved a quarterly average sales
volume record of 158 MBoe/d. Our activities were focused primarily on
progressing development in the Mustang, which benefits from our approved CDP,
Wells Ranch and East Pony areas. We continue to see increased capital
efficiencies as a result of improved drilling and completion performance. In the
Mustang, we utilized our first electric powered drilling rig, resulting in
reduced noise, emissions and fuel costs.
In addition, we submitted an application for approval of the North Wells Ranch
CDP. This CDP covers approximately 38,000 net acres and up to 250 potential
drilling permits. Final approval is targeted for early 2020.
Delaware Basin During third quarter 2019, we achieved a quarterly average sales
volume record of 70 MBoe/d. Our activity focused primarily on drilling and
completion optimization, leading to capital and operational cost efficiencies.
We brought online our first field power substation, which will provide a
reliable power source to support field operations.
Eagle Ford Shale During third quarter 2019, we focused on maximizing cash flows
from existing production and conducted two well refractures on Gates Ranch. We
continue to evaluate and assess our development plan for the area and are
incorporating learnings from our refracture results.
International
Leviathan Natural Gas Project (Offshore Israel) As of September 30, 2019, the
project was over 90% complete and is ahead of schedule and below budget. During
third quarter 2019, the topsides set sail and arrived in Israel, where they were
installed, and we completed all subsea construction scope and pre-commissioning
activities. The remaining commissioning and operational readiness activities are
underway, with first production anticipated in December 2019.
Leviathan and Tamar Gas Sales and Purchase Agreements (Offshore Israel) In
October 2019, we announced that we and our partners had amended the agreements
for the sale of natural gas to Dolphinus Holdings Limited from the Leviathan and
Tamar fields. The amended agreements, which are subject to certain regulatory
approvals, provide for total combined firm contract quantities of 3.0 trillion
cubic feet (Tcf) of natural gas, more than doubling the firm volume commitments
previously agreed. In addition, each agreement has been extended by five years
to reflect 15-year terms and include take-or-pay commitments.
During the two-year period ending June 30, 2022, the Leviathan field will
backstop any volume commitment that the Tamar field is unable to deliver under
the amended agreement.
EMG Pipeline (Offshore Israel) During third quarter 2019, we funded a $185
million investment in EMED Pipeline B.V. in support of its planned acquisition
of an approximate 39% equity interest in EMG, which owns the EMG Pipeline. Upon
closing of the planned equity transaction, which is anticipated in fourth
quarter 2019, we will own an effective, indirect interest of

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approximately 10%, net, in EMG. The EMG Pipeline will support delivery of
natural gas from our producing fields offshore Israel into Egypt.
Aseng Development Well (Offshore Equatorial Guinea) During third quarter 2019,
the Aseng field surpassed 100 MMBbl of crude oil produced. In addition, we
drilled and completed a development well which is expected to mitigate field
decline. Production came online in October 2019.
Alen Natural Gas Development (Offshore Equatorial Guinea)   In second quarter
2019, we announced the sanction of the Alen natural gas development. Natural gas
from the Alen field will be processed through the existing Alba Plant
LLC liquefied petroleum gas (LPG) processing plant (Alba Plant) and Equatorial
Guinea's LNG production facility (EG LNG) located at Punta Europa, Bioko Island.
Definitive agreements in support of the project have been executed among the
Alen field partners, the Alba Plant and EG LNG plant owners, as well as the
government of the Republic of Equatorial Guinea.
The Alen natural gas monetization project will produce through three existing
high-capacity wells and will require minor platform modifications to deliver
sales gas from the Alen field to the Alba Plant and EG LNG facilities. The Alen
field partners plan to construct a 24-inch pipeline capable of handling 950
MMcfe/d to transport all natural gas processed through the Alen platform
approximately 70 kilometers to the onshore facilities. First production is
anticipated in the first half of 2021. At start-up, natural gas sales from the
Alen field are anticipated to be between 200 and 300 MMcfe/d, gross
(approximately 75 to 115 MMcfe/d, net). The wet gas stream will be tolled
through the Alba Plant for additional liquids recovery before the dry gas is
converted into LNG at the EG LNG facility.
Unsanctioned Projects
Cyprus Natural Gas Project (Offshore Cyprus) We continue to work with the
Government of Cyprus on a plan of development for the Aphrodite field that, as
currently contemplated, would deliver natural gas to regional customers. In
addition, we are focused on capital cost improvements, as well as natural gas
marketing efforts and execution of natural gas sales and purchase agreements,
which, once secured, will progress the project to a final investment decision.
Exploration Program Update
US Onshore Acreage Our US onshore unconventional exploration position includes
more than 175,000 acres residing in two plays in Wyoming. During third quarter
2019, we progressed activities to obtain required approvals and permits in
support of planned future drilling activities.
Offshore Colombia We have signed an agreement for a 40% operated working
interest in more than two million gross acres offshore Colombia, located on two
blocks. We expect to drill an exploration well in 2020. During third quarter
2019, we continued well planning and permitting activities.
Potential for Future Dry Hole Costs, Lease Abandonment Expense or Property
Impairments
Exploration Activities We continue to seek and evaluate significant onshore
and/or offshore opportunities for future exploration. Through our drilling
activities, we do not always encounter hydrocarbons or we may find hydrocarbons
but subsequently reach a decision, through additional analysis or appraisal
drilling, that a development project is not economically or operationally
viable. Additionally, we may not be able to conduct exploration activities prior
to lease expirations or may choose to relinquish or exit licenses or leases.
Therefore, future dry hole cost and/or leasehold abandonment expense could be
significant. See   Item 1. Financial Statements - Note   5. Capitalized
Exploratory Well Costs and Undeveloped Leasehold Costs.
Producing Properties A decline in future commodity prices could result in some
of our properties becoming uneconomic, resulting in an impairment charge,
decrease in proved reserves and/or shut-in of currently producing wells. In
addition, in certain US onshore areas, transportation bottlenecks caused by
production above transportation capacity and/or lack of infrastructure may
reduce the amount of production reaching markets, resulting in lower in-basin
pricing (i.e. higher basis differential). An increase in basis differentials
could also reduce cash flows and result in property impairment charges.
Results of Operations
Third Quarter 2019 E&P Operating Highlights Included:
• total average consolidated sales volumes of 379 MBoe/d, net;


• record average daily sales volumes of 127 MBbl/d, net, for US crude oil;

• average daily sales volumes of 1.1 Bcfe/d, gross, of natural gas from the

Tamar field, offshore Israel;

• reached total gross volumes of 2 Tcf of natural gas produced from the

Tamar field; and

• commencement of crude oil shipments on the EPIC Y-Grade pipeline, which

began interim crude service in August.

Third Quarter 2019 E&P Financial Results Included: • additions to equity method investments of $185 million, as compared with

zero for third quarter 2018;

• capital expenditures, excluding acquisitions, of $540 million, as compared

       with $696 million for third quarter 2018;


•      pre-tax income of $205 million, as compared with $225 million for third
       quarter 2018; and



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• net gain on commodity derivative instruments of $129 million, as compared

with a net loss of $155 million for third quarter 2018.

The following is a summarized statement of operations for our E&P business:

                                                 Three Months Ended 

September Nine Months Ended

                                                              30,                     September 30,
(millions)                                           2019             2018          2019         2018
Oil, NGL and Gas Sales to Third Parties          $   1,003$   1,136$   2,894$ 3,409
Sales of Purchased Oil and Gas                          22                 -            64           -
Income from Equity Method Investments and Other         15                34            48         105
Total Revenues                                       1,040             1,170         3,006       3,514
Production Expense                                     370               316         1,019         997
Exploration Expense                                     25                25            82          89
Depreciation, Depletion and Amortization               544               456         1,512       1,336
Loss (Gain) on Divestitures, Net                         -                 5             -        (356 )
Asset Impairments                                        -                 -             -         168
Cost of Purchased Oil and Gas                           17                 -            59           -
(Gain) Loss on Commodity Derivative Instruments       (129 )             155            23         483
Income Before Income Taxes                             205               225           216         720




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Average Oil, NGL and Gas Sales Volumes and Prices Average daily sales volumes from our share of production and realized sales prices were as follows:

                              Average Sales Volumes (1)                     

Average Realized Sales Prices (1)

                Crude Oil &                                               Crude Oil &
                 Condensate       NGLs       Natural Gas      Total        Condensate         NGLs          Natural Gas
                  (MBbl/d)      (MBbl/d)      (MMcf/d)       (MBoe/d)      (Per Bbl)        (Per Bbl)        (Per Mcf)
Three Months Ended September 30, 2019
United States          127           76             542          293     $      55.13$     11.18$        1.57
Eastern
Mediterranean            -            -             231           39                -               -              5.55
West Africa (2)         15            -             190           47            58.62               -              0.27
Total
Consolidated
Operations (3)         142           76             963          379            55.48           11.18              2.27
Equity
Investments (4)          1            5               -            6            57.44           25.85                 -
Total (3)              143           81             963          385     $      55.50$     12.06$        2.27
Three Months Ended September 30, 2018United States
(5)                    109           63             464          249     $      65.54$     28.58$        2.31
Eastern
Mediterranean            -            -             241           41                -               -              5.49
West Africa (2)         13            -             217           49            73.70               -              0.27
Total
Consolidated
Operations             122           63             922          339            66.41           28.58              2.66
Equity
Investments (4)          1            5               -            6            74.88           48.27                 -
Total                  123           68             922          345     $      66.50$     29.92$        2.66
Nine Months Ended September 30, 2019
United States          119           67             507          270     $      55.59$     14.22$        1.87
Eastern
Mediterranean            -            -             224           38                -               -              5.55
West Africa (2)         13            -             186           44            61.75               -              0.27
Total
Consolidated
Operations (3)         132           67             917          352            56.18           14.22              2.45
Equity
Investments (4)          1            4               -            5            59.81           30.94                 -
Total (3)              133           71             917          357     $      56.22$     15.23$        2.45
Nine Months Ended September 30, 2018United States
(5)                    113           63             479          255     $      63.98$     26.22$        2.42
Eastern
Mediterranean            -            -             242           41                -               -              5.48
West Africa (2)         15            -             216           51            71.55               -              0.27
Total
Consolidated
Operations             128           63             937          347            64.86           26.22              2.71

Equity

Investments (4)          2            5               -            7            72.46           43.70                 -
Total                  130           68             937          354     $      64.95$     27.50$        2.71

(1) Natural gas is converted on the basis of six Mcf of gas per one barrel of

crude oil equivalent (BOE). This ratio reflects an energy content

equivalency and not a price or revenue equivalency. Given commodity price

disparities, the prices for a barrel of crude oil equivalent for US natural

gas and NGLs are significantly less than the price for a barrel of crude

oil. In Israel, we sell natural gas under contracts where the majority of

the price is fixed, resulting in less commodity price disparity between

reporting periods.

(2) Natural gas from the Alba field is sold under contract for $0.25 per MMBtu

     to a methanol plant, an LPG plant, an LNG plant and a power generation
     plant. The methanol and LPG plants are owned by affiliated entities
     accounted for under the equity method.

(3) Includes a small amount of condensate sales from offshore Israel assets.


(4)  Volumes represent sales of condensate and LPG from the LPG plant in
     Equatorial Guinea. See Income from Equity Method Investments.

(5) Includes 9 MBoe/d for first nine months of 2018 related to Gulf of Mexico

     assets sold in second quarter 2018. See   Item 1. Financial Statements -
     Note   4. Acquisitions and Divestitures.



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An analysis of revenues from sales of crude oil, NGLs and natural gas is as follows:

                                         Crude Oil &
(millions)                                Condensate           NGLs        Natural Gas        Total
Three Months Ended September 30, 2018 $         744        $      166$        226$    1,136
Changes due to
Increase in Sales Volumes                       123                30                7            160
Decrease in Sales Prices (1)                   (143 )            (118 )            (32 )         (293 )
Three Months Ended September 30, 2019 $         724        $       78     $ 

201 $ 1,003

Nine Months Ended September 30, 2018$ 2,266$ 449 $

        694     $    3,409
Changes due to
Increase (Decrease) in Sales Volumes            123                22              (30 )          115
Decrease in Sales Prices (1)                   (365 )            (213 )            (52 )         (630 )
Nine Months Ended September 30, 2019  $       2,024$      258     $ 

612 $ 2,894

(1) Changes exclude gains and losses related to commodity derivative

instruments. See Item 1. Financial Statements - Note 12. Derivative

Instruments and Hedging Activities.



Crude Oil and Condensate Sales Revenues Revenues from crude oil and condensate
sales decreased in third quarter and the first nine months of 2019 as compared
with 2018 primarily due to the following:
•      decreases in average realized prices for third quarter and the first nine

months of 2019 (see Executive Overview - Operational Environment Update

- Commodity Prices );

• reduction in sales volumes of 7 MBbl/d for the first nine months of 2019

       due to the sale of our Gulf of Mexico assets in second quarter 2018; and

• lower West Africa sales volumes of 2 MBbl/d for the first nine months of

2019 due to timing of liftings and natural field decline;

partially offset by: • higher US onshore sales volumes of 18 MBbl/d and 13 MBbl/d for third

quarter and the first nine months of 2019, respectively, primarily due to

       an increase in development activity in the DJ and Delaware Basins.


NGL Sales Revenues Revenues from NGL sales decreased in third quarter and the
first nine months of 2019 as compared with 2018 primarily due to the following:
•      decreases in average realized prices for third quarter and the first nine

months of 2019 (see Executive Overview - Operational Environment Update

- Commodity Prices ); and

• lower Eagle Ford Shale sales volumes of 8 MBbl/d for the first nine months

of 2019 due to reduced activity and natural field decline;

partially offset by: • higher sales volumes in the DJ and Delaware Basins of 12 MBbl/d and 12

MBbl/d for third quarter and the first nine months of 2019, respectively,

due to an increase in development activities.



Natural Gas Sales Revenues Revenues from natural gas sales decreased in third
quarter and the first nine months of 2019 as compared with 2018 primarily due to
the following:
•      decreases in average realized prices for third quarter and the first nine

months of 2019 (see Executive Overview - Operational Environment Update

- Commodity Prices );

• lower Eagle Ford Shale sales volumes of 10 MMcf/d and 51 MMcf/d for third

quarter and the first nine months of 2019, respectively, due to reduced

       activity and natural field decline;


•      lower West Africa sales volumes of 27 MMcf/d and 30 MMcf/d for third

quarter and the first nine months of 2019, respectively, due to natural

field decline and planned maintenance at onshore facilities during first

quarter 2019, which required field shut-in for a portion of the period;

and

• lower Israel sales volumes of 10 MMcf/d and 18 MMcf/d for third quarter

and the first nine months of 2019, respectively, primarily due to planned

       maintenance and the sale of a 7.5% interest in the Tamar field in March
       2018;

partially offset by: • higher sales volumes in the DJ and Delaware Basins of 88 MMcf/d and 87

MMcf/d for third quarter and the first nine months of 2019, respectively,

due to an increase in development activities.



Sales and Cost of Purchased Oil and Gas  In third quarter and the first nine
months of 2019, we engaged in third party sales and purchases of crude oil in
the DJ Basin for flow assurance on pipelines used to deliver our production to
market.

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Income from Equity Method Investments and Other  Income from equity method
investments and other decreased in the first nine months of 2019 as compared
with 2018. The decrease includes a $34 million decrease from Atlantic Methanol
Production Company, LLC (AMPCO), our methanol investment, and a $24 million
decrease from Alba Plant, our LPG investment, primarily due to decreases in
average realized methanol and LPG prices and plant downtime due to planned
maintenance activities.
Production Expense  Components of production expense were as follows:
                                Total per BOE                  United States         Eastern
(millions, except unit rate)        (1)(2)          Total           (2)           Mediterranean        West Africa
Three Months Ended September
30, 2019
Lease Operating Expense (3)     $       4.02$     140$       111     $               7     $          22
Production and Ad Valorem Taxes         1.47            51              51                     -                 -
Gathering, Transportation and
Processing                              5.00           174             173                     1                 -
Other Royalty Expense                   0.14             5               5                     -                 -
Total Production Expense        $      10.64$     370$       340     $               8     $          22
Total Production Expense per
BOE                                              $   10.64$     12.61     $            2.24     $        5.17
Three Months Ended September
30, 2018
Lease Operating Expense (3)     $       4.37$     136$       114     $               7     $          15
Production and Ad Valorem Taxes         1.48            46              46                     -                 -
Gathering, Transportation and
Processing                              4.14           129             129                     -                 -
Other Royalty Expense                   0.16             5               5                     -                 -
Total Production Expense        $      10.15$     316$       294     $               7     $          15
Total Production Expense per
BOE                                              $   10.15$     12.82     $            1.90     $        3.32
Nine Months Ended September 30,
2019
Lease Operating Expense (3)     $       4.50$     432$       350     $              26     $          56
Production and Ad Valorem Taxes         1.44           138             138                     -                 -
Gathering, Transportation and
Processing                              4.59           440             439                     1                 -
Other Royalty Expense                   0.09             9               9                     -                 -
Total Production Expense        $      10.63$   1,019$       936     $              27     $          56
Total Production Expense per
BOE                                              $   10.63$     12.70     $            2.63     $        4.70
Nine Months Ended September 30,
2018
Lease Operating Expense (3)     $       4.54$     429$       354     $              19     $          56
Production and Ad Valorem Taxes         1.55           147             147                     -                 -
Gathering, Transportation and
Processing                              4.11           389             389                     -                 -
Other Royalty Expense                   0.34            32              32                     -                 -
Total Production Expense        $      10.54$     997$       922     $              19     $          56
Total Production Expense per
BOE                                              $   10.54$     13.22     $            1.73     $        4.04

(1) Consolidated unit rates exclude sales volumes and expenses attributable to

equity method investments.

(2) US production expense includes charges from our midstream operations that

are eliminated on a consolidated basis.

(3) Lease operating expense includes oil and gas operating costs (labor, fuel,

repairs, replacements, saltwater disposal and other related lifting costs)

and workover expense.

Production expense for third quarter and the first nine months of 2019 increased as compared with 2018, primarily due to the following: • increase in US gathering, transportation and processing (GTP) expense

primarily due to increased development activities in our DJ and Delaware

Basins and higher rates in our DJ Basin;

• increase in Eastern Mediterranean lease operating expense due to planned

maintenance activities; and

• increase in West Africa lease operating expense due to increase in volumes

lifted from the higher-cost Alen field;

partially offset by: • decrease in US lease operating expense primarily due to the sale of our

Gulf of Mexico assets and cost reduction efforts in our US onshore basins;

and

• decrease in US other royalty expense due to lower commodity prices.

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The unit rate per BOE increased for third quarter and the first nine months of
2019 as compared with 2018 primarily due to an increase in GTP expense, as noted
above, and an increase in volumes from higher-cost areas within US onshore and
West Africa, partially offset by cost reduction efforts in our US onshore
basins.
Exploration Expense Exploration expense for third quarter and the first nine
months of 2019 totaled $25 million and $82 million, respectively, including
staff expense of $10 million and $34 million, respectively. Exploration expense
for third quarter and the first nine months of 2018 totaled $25 million and $89
million, respectively, including staff expense of $14 million and $41 million,
respectively.
Depreciation, Depletion and Amortization (DD&A) Expense DD&A expense was as
follows:
                                                                        

Eastern

(millions, except unit rate)       Total        United States        Mediterranean        West Africa       Other Int'l
Three Months Ended September
30, 2019
DD&A Expense                    $     544     $           505     $              17     $          21     $            1
Unit Rate per BOE (1)           $   15.64     $         18.73     $            4.76     $        4.94     $            -
Three Months Ended September
30, 2018
DD&A Expense                    $     456     $           414     $              16     $          25     $            1
Unit Rate per BOE (1)           $   14.64     $         18.05     $            4.34     $        5.53     $            -
Nine Months Ended September 30,
2019
DD&A Expense                    $   1,512     $         1,401     $              50     $          60     $            1
Unit Rate per BOE (1)           $   15.77     $         19.01     $            4.86     $        5.04     $            -
Nine Months Ended September 30,
2018
DD&A Expense                    $   1,336     $         1,214     $              44     $          77     $            1
Unit Rate per BOE (1)           $   14.12     $         17.41     $            4.00     $        5.55     $            -

(1) Consolidated unit rates exclude sales volumes and expenses attributable to

equity method investments.

DD&A expense for third quarter and the first nine months of 2019 increased as compared with 2018, primarily due to the following: • capital investment and development activities in the DJ and Delaware

Basins resulting in higher sales volumes; and

• increase in Eastern Mediterranean due to the retirement of certain capital

assets resulting in accelerated depreciation;

partially offset by: • decrease resulting from the sale of our Gulf of Mexico assets in second

       quarter 2018; and


•      reduced sales volumes in West Africa, as noted above, and reserves
       additions subsequent to third quarter 2018.


The unit rate per BOE for third quarter and the first nine months of 2019
increased as compared with 2018, primarily due to the increase in total DD&A
expense, as noted above. Specifically, development activity increased in the
higher-cost Delaware Basin and the 2018 sale of lower-cost Tamar reserves
increased the overall unit rate per BOE. The rate was also impacted by year-end
2018 update to proved reserves quantities used to calculate DD&A, which
reflected negative non-price reserves revisions recorded for the Delaware Basin
attributable to changes in expected recoveries and higher operating and capital
costs. The increase in the unit rate is partially offset by the sale of
higher-cost production from the Gulf of Mexico assets.
Loss on Commodity Derivative Instruments  Loss on commodity derivative
instruments for the first nine months of 2019 decreased as compared with 2018.
For the first nine months of 2019, loss on commodity derivative instruments
included:
• net cash receipts of $28 million; and


•               net non-cash decrease of $51 million in the fair value of our net
           commodity derivative asset, primarily driven by changes in the forward
                                         commodity price curves for crude oil.

For the first nine months of 2018, loss on commodity derivative instruments included: • net cash payments of $160 million; and

• net non-cash decrease of $323 million in the fair value of our net

commodity derivative liability, primarily driven by changes in the forward

commodity price curves for crude oil.

See Item 1. Financial Statements - Note 12. Derivative Instruments and Hedging Activities.

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RESULTS OF OPERATIONS - MIDSTREAM
The Midstream segment develops, owns and operates domestic midstream
infrastructure assets, as well as invests in other midstream projects, with
current focus in the DJ and Delaware Basins.
Results of Operations
Third Quarter 2019 Midstream Operating Highlights and Financial Results
Included:
•      entered into a strategic relationship with Saddlehorn Pipeline Company,
       LLC (Saddlehorn);


•      total revenues of $186 million, as compared with $168 million for third
       quarter 2018;


•      pre-tax income of $83 million, as compared with pre-tax income of $268
       million for third quarter 2018; and


•      additions to equity method investments of $86 million, as compared with
       zero for third quarter 2018.

The following is a summarized statement of operations for our Midstream segment:

                                           Three Months Ended September 30,           Nine Months Ended September 30,
(millions)                                    2019                   2018                2019                 2018
Midstream Services Revenues - Third
Party                                  $          19           $            21     $          63         $          49
Sales of Purchased Oil and Gas                    47                        46               132                   110
(Loss) Income from Equity Method
Investments                                       (5 )                      10                (5 )                  35
Intersegment Revenues                            125                        91               322                   257
Total Revenues                                   186                       168               512                   451
Operating Costs and Expenses                      31                        30               108                    96
Depreciation, Depletion and
Amortization                                      26                        24                77                    62
Gain on Divestitures, Net                          -                      (198 )               -                  (503 )
Cost of Purchased Oil and Gas                     46                        44               125                   106
Total Expense (Income)                           103                      (100 )             310                  (239 )
Income Before Income Taxes             $          83           $           

268 $ 202 $ 690



Midstream Services Revenues - Third Party The amount of revenue generated by the
Midstream segment depends primarily on the volumes of crude oil, natural gas and
water for which services are provided to dedicated acreage for our E&P business
and to third-party customers. These volumes are affected by the level of
drilling and completion activity and by changes in the supply of, and demand
for, crude oil, NGLs and natural gas in the markets served directly or
indirectly by our midstream assets.
Midstream services revenues for the first nine months of 2019 increased as
compared with 2018, primarily due to increases in crude oil, natural gas and
produced water gathering services and fresh water delivery. The increases were
due primarily to higher Delaware Basin throughput volumes, commencement of
services in the Mustang IDP in 2018, and services related to the Black Diamond
system, which was acquired during first quarter 2018 in the Saddle Butte
acquisition.
Sales and Costs of Purchased Oil and Gas Sales and costs of purchased oil for
third quarter and the first nine months of 2019 increased as compared with 2018
due to a full nine months of services related to the Black Diamond system.
(Loss) Income from Equity Method Investments Income from equity method
investments decreased for third quarter and the first nine months of 2019 as
compared with 2018, primarily due to the sale of our investment in CNX Midstream
Partners in second quarter 2018 and operating losses associated with EPIC
Y-Grade, EPIC Crude Holdings and Delaware Crossing. Operating losses were
primarily due to expenses incurred for the formation of the joint ventures and
general and administrative expenses incurred prior to service commencement.
Operating Costs and Expenses Operating costs and expenses for third quarter and
the first nine months of 2019 increased as compared with 2018, primarily due to
an increase in gathering systems operating expense associated with the Delaware
Basin central gathering facilities (CGF) that were completed during 2018,
additional expenses associated with the Black Diamond system and expenses
associated with the commencement of gathering services in the Mustang IDP in
2018.
DD&A Expense DD&A expense for third quarter and the first nine months of 2019
increased as compared with 2018, primarily due to certain assets being placed in
service subsequent to third quarter 2018, including the Mustang IDP gathering
system, the Delaware Basin CGFs, and additional Black Diamond assets. In
addition, DD&A expense includes a full nine months of amortization related to
intangible assets acquired in the Saddle Butte acquisition.
Gain on Divestitures, Net Gain on divestitures, net relates to 2018 sales of our
interest in CONE Gathering and our investment in CNX Midstream Partners. See

Item 1. Financial Statements - Note 4. Acquisitions and Divestitures .

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Saddlehorn In third quarter 2019, Noble Midstream Partners entered into a
strategic relationship with Saddlehorn, resulting in new long-term firm
transportation commitments and an option to acquire up to a 20% ownership
interest in Saddlehorn, which transports crude oil and condensate from the DJ
and Powder River Basins to storage facilities in Cushing, Oklahoma. The
investment option expires in April 2020.
RESULTS OF OPERATIONS - CORPORATE
Expenses related to debt, such as interest and other debt-related costs,
headquarters depreciation, corporate general and administrative (G&A) expenses,
exit costs and certain costs associated with mitigating the effects of our
retained Marcellus Shale transportation agreements, are recorded at the
Corporate level.
Transportation Exit Cost Revenues and expenses associated with retained
Marcellus Shale transportation contracts were as follows:
                                        Three Months Ended September 30,     Nine Months Ended September 30,
(millions)                                    2019              2018              2019              2018
Sales of Purchased Gas (1)             $             18     $        26     $            68     $        81
Cost of Purchased Gas (1)                            33              32                 112              98
Firm Transportation Exit Cost (2)                     -               -                  92               -


(1) Relates to third party mitigation activities we engage in to utilize a

portion of our Marcellus Shale transportation commitment. Cost of purchased

gas includes utilized and unutilized transportation expense. Amounts for the

     nine months ended 2019 increased as compared to 2018 due to increased
     transportation expense for pipelines that came into service in fourth
     quarter 2018.

(2) Represents exit costs related to future commitments to a third party

resulting from a permanent capacity assignment.

See Item 1. Financial Statements - Note 9. Exit Cost - Transportation Commitments. General and Administrative Expense G&A expense was as follows:

                                       Three Months Ended September 30,     Nine Months Ended September 30,
(millions, except unit rate)                  2019              2018              2019              2018
G&A Expense                            $             91     $      107     $            298     $      316
Unit Rate per BOE (1)                  $           2.62     $     3.44     $           3.11     $     3.34

(1) Consolidated unit rates exclude sales volumes and expenses attributable to

equity method investments.



Due to our focus on overall G&A cost reductions, expense for third quarter and
the first nine months of 2019 decreased as compared with 2018, and we achieved a
15% reduction as compared to third quarter 2018. Decreases were primarily due to
reduced employee, office and travel expenses, partially offset by increases in
technology costs. The unit rate per BOE for third quarter and the first nine
months of 2019 also decreased as compared with 2018 due to the reduction in G&A
expense and the increase in the total sales volumes.
Interest Expense and Capitalized Interest  Interest expense and capitalized
interest were as follows:
                                          Three Months Ended September 30,           Nine Months Ended September 30,
(millions, except unit rate)                  2019                  2018                2019                  2018
Interest Expense, Gross                $           92         $           88     $          269         $          269
Capitalized Interest                              (25 )                  (18 )              (73 )                  (53 )
Interest Expense, Net                  $           67         $           70     $          196         $          216
Unit Rate per BOE (1)                  $         1.93         $         2.25     $         2.04         $         2.28

(1) Consolidated unit rates exclude sales volumes and expenses attributable to

equity method investments.



Interest expense, gross, for third quarter and the first nine months of 2019
remained relatively flat as compared with 2018. See   Item 1. Financial
Statements - Note   7. Debt. Capitalized interest for third quarter and the
first nine months of 2019 increased as compared with 2018, primarily due to
higher work in progress amounts related to Leviathan development and additions
to equity method investments engaged in construction activities.
The unit rate per BOE for third quarter and the first nine months of 2019
decreased as compared with 2018, primarily due to the reduction in net interest
expense, noted above, and the increase in total sales volumes.
LIQUIDITY AND CAPITAL RESOURCES
Capital Structure/Financing Strategy
In seeking to effectively fund and monetize our discovered hydrocarbons, we
employ a capital structure and financing strategy designed to provide sufficient
liquidity throughout commodity price cycles, including a sustained period of low
prices.

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Specifically, we strive to retain the ability to fund long cycle, multi-year,
capital intensive development projects throughout a range of scenarios, while
also funding a continuing exploration program and maintaining capacity to
capitalize on financially attractive merger and acquisition opportunities. We
endeavor to maintain a strong balance sheet and an investment grade debt rating
in service of these objectives.
We strive to maintain a minimum liquidity level to address volatility and risk.
Traditional sources of liquidity are cash flows from operations, cash on hand,
proceeds from divestitures of properties and other investments, and available
borrowing capacity under our $4.0 billion unsecured Revolving Credit Facility.
We occasionally access the capital markets to ensure adequate liquidity exists
in the form of unutilized capacity under our Revolving Credit Facility or to
refinance scheduled debt maturities. Refer to Noble Midstream Services 2019 Term
Loan Credit Facility and Subsequent Event below for recently completed capital
market activities.
Supported by our investment grade credit rating, we established a $4.0 billion
commercial paper program in first quarter 2019. This program can be accessed as
needed to supplement operating cash flows for short-term funding needs. In
addition, we may from time to time seek to retire or purchase our outstanding
senior notes through cash purchases in the open market, privately negotiated
transactions or otherwise. Such repurchases, if any, will depend on prevailing
market conditions, our liquidity requirements, contractual restrictions and
other factors.
We also evaluate potential strategic farm-out arrangements of our working
interests for reimbursement of our capital spending. We periodically consider
repatriations of foreign cash to increase our financial flexibility and fund our
capital investment program. Additionally, we enter into crude oil and natural
gas price hedging arrangements in an effort to mitigate the effects of commodity
price volatility and enhance the predictability of cash flows relating to the
marketing of a portion of our crude oil and natural gas production.
Thus far in 2019, we have funded our capital program with cash flows from
operations, cash on hand, commercial paper borrowings, and proceeds from
divestments of non-strategic assets. We did not repurchase any shares of Noble
Energy common stock under the Board of Directors-authorized $750 million share
repurchase program during the first nine months of 2019.
Third Quarter 2019 Highlights
During third quarter 2019, we completed the following financing activities:
•      borrowed $271 million, net, under our $4.0 billion commercial paper

program for working capital purposes;

• repaid $320 million, net, under the Noble Midstream Services Revolving

       Credit Facility; and


•      borrowed $400 million under the Noble Midstream Services 2019 Term Loan

Credit Facility, primarily to repay a portion of borrowings outstanding

under the Noble Midstream Services Revolving Credit Facility.



Available Liquidity
The following table summarizes our cash, debt and available liquidity:
                                      September 30, 2019                                 December 31, 2018
                         Noble Energy                                      Noble Energy
                           Excluding                                         Excluding
(millions, except       Noble Midstream   Noble Midstream                 Noble Midstream   Noble Midstream
percentages)               Partners           Partners         Total         Partners           Partners         Total
Total Cash (1)          $         455     $           18     $    473     $         707     $           12     $    719
Amounts Available for
Borrowing (2)                   3,489                  -        3,489             4,000                  -        4,000
Total Liquidity         $       3,944     $           18     $  3,962$       4,707     $           12     $  4,719

Total Debt (3)          $       6,601     $          950     $  7,551$       6,115     $          560     $  6,675
Noble Energy Share of
Equity                                                       $  9,004$  9,426Ratio of Debt-to-Book
Capital (4)                                                        46 %                                              41 %

(1) Total cash includes $3 million of restricted cash at December 31, 2018.

(2) Excludes amounts available to be borrowed under the Noble Midstream Services

     Revolving Credit Facility, which is not available to Noble Energy for
     general corporate purposes.

(3) Total debt excludes unamortized debt discount/premium and debt issuance

costs. See Item 1. Financial Statements - Note 7. Debt.

(4) We define our ratio of debt-to-book capital as total debt divided by the sum

of total debt plus Noble Energy's share of equity.



Cash and Cash Equivalents  We had $473 million in cash and cash equivalents at
September 30, 2019, primarily denominated in US dollars and invested in money
market funds and short-term deposits with major financial institutions.
Approximately

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$430 million of this cash is attributable to our foreign subsidiaries. We do not
expect to incur significant US income tax expense with respect to future
repatriation of foreign cash.
Revolving Credit Facilities and Commercial Paper Program Noble Energy's $4.0
billion Revolving Credit Facility and the $800 millionNoble Midstream Services
Revolving Credit Facility both mature in 2023. These facilities are used to fund
capital investment programs and acquisitions and may periodically provide
amounts for working capital purposes. Additionally, in first quarter 2019, we
established a commercial paper program to provide for short-term funding needs.
The program allows for a maximum of $4.0 billion of unsecured commercial paper
notes and is supported by Noble Energy's Revolving Credit Facility.
At September 30, 2019, outstanding commercial paper borrowings of $511 million
reduced the amount available for borrowing under Noble Energy's Revolving Credit
Facility to approximately $3.5 billion. Additionally, at September 30, 2019, $50
million was outstanding under the Noble Midstream Services Revolving Credit
Facility, leaving $750 million available for borrowing. See   Item 1. Financial
Statements - Note   7. Debt.
Noble Midstream Services 2019 Term Loan Credit Facility In August 2019, Noble
Midstream Services entered into a three-year senior unsecured term loan
agreement, which provides for aggregate borrowings of up to $400 million. Noble
Midstream Services borrowed $400 million in third quarter 2019. See   Item 1.
Financial Statements - Note   7. Debt.
GIP Preferred Equity Commitment In March 2019, Noble Midstream Partners secured
a $200 million preferred equity commitment from GIP to fund capital
contributions to Dos Rios Crude Intermediate LLC, a newly-formed subsidiary
holding Noble Midstream Partners' 30% equity interest in EPIC Crude Holdings. Of
the $200 million total commitment, $100 million was funded, with the remaining
$100 million available for a one year period, subject to certain conditions
precedent. See   Item 1. Financial Statements - Note   4. Acquisitions and
Divestitures.
Subsequent Event On October 1, 2019, we issued $1.0 billion of notes, using
proceeds from the issuance to fund the tender offer and redemption of our $1.0
billion 4.15% notes due December 15, 2021. In connection with the tender and
redemption, in fourth quarter 2019, we will record early debt extinguishment
fees of approximately $44 million in our consolidated statements of operations.
See   Item 1. Financial Statements - Note   7. Debt.
Contractual Obligations
Marcellus Shale Transportation Commitments We have remaining financial
commitments of approximately $1.0 billion, undiscounted, associated with
Marcellus Shale transportation contracts. See   Item 1. Financial Statements -
Note   9. Exit Cost - Transportation Commitments.
Letters of Credit In the ordinary course of business, we maintain letters of
credit and bank guarantees with a variety of banks in support of certain
performance obligations of our subsidiaries. Outstanding letters of credit and
bank guarantees, including those of Noble Midstream Partners, totaled
approximately $121 million at September 30, 2019.
Cash Flows
The following table summarizes our total cash provided by (used in) operating,
investing and financing activities:
                                                                 Nine Months Ended September 30,
 (millions)                                                        2019                   2018
Operating Activities                                        $         1,529         $         1,776
Investing Activities                                                 (2,528 )                (1,502 )
Financing Activities                                                    753                    (266 )
(Decrease) Increase in Cash, Cash Equivalents and
Restricted Cash                                             $          (246 )       $             8


Operating Activities  Cash provided by operating activities for the first nine
months of 2019 decreased $247 million as compared with 2018. The decrease was
primarily driven by a decrease in net revenues driven by lower commodity prices
and higher production costs attributable to increased operational activity in US
onshore, partially offset by cash received in settlements for commodity
derivatives of $28 million, as compared with cash payments of $160 million in
the prior year.
Investing Activities  Cash used in investing activities increased approximately
$1.0 billion for the first nine months of 2019 as compared with 2018, primarily
due to a decrease in net proceeds provided by divestitures and additions to
equity method investments of $686 million. These were partially offset by a
decrease in capital spending for property, plant and equipment and the absence
of spending on acquisitions, compared to $653 million in the prior year.
Financing Activities  Our financing activities during the first nine months of
2019 included net borrowings of $511 million under the commercial paper program,
Noble Midstream Partners' borrowings of $400 million on the Noble Midstream
Services 2019 Term Loan Credit Facility, the receipt of $97 million of GIP
preferred equity, net of offering costs, and net repayments of

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$10 million on the Noble Midstream Services Revolving Credit Facility. Proceeds
from the 2019 Term Loan Credit Facility were used to repay borrowings on Noble
Midstream Services Revolving Credit Facility. In addition, during the first nine
months of 2019, we paid $168 million of cash dividends to Noble Energy
shareholders.
Our financing activities during the first nine months of 2018 included a
$230 million, net, Revolving Credit Facility repayment and $35 million, net,
Noble Midstream Services Revolving Credit Facility repayment, which included
borrowings of $465 million primarily used to fund the Saddle Butte acquisition,
offset by a repayment of $500 million drawn under the Noble Midstream Services
2018 Term Loan Credit Facility. We used $384 million of cash to redeem senior
notes, repurchased $223 million of common stock pursuant to our stock repurchase
program, paid $156 million of cash dividends to Noble Energy shareholders and
paid $35 million of cash distributions to Noble Midstream Partners
noncontrolling interest owners. We also received $348 million of contributions
from noncontrolling interest owners. See   Item 1. Financial Statements -
Consolidated Statements of Cash Flows  .
Capital Expenditure Activities
Our capital expenditures (on an accrual basis) were as follows:

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