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We are Noble
Energizing the World
Bettering People’s Lives®
Date
Title
2017Annual Report
Financial Discipline
p Capital efficiency focus
p Capital deployed to
highest returns
p Comprehensive risk
management
Exceptional Portfolio
p High-return,
high-margin focus
p Active management
captures full value
p Material exploration
opportunities
Operational Execution
p Safe and responsible
p Industry-leading
execution
p Integrated upstream/
midstream
“ This was a
transformative year.”
David L. Stover, Chairman, President and CEO
DEAR FELLOW SHAREHOLDERS,
This was a transformative year for Noble Energy as we
sharpened our
focus. We executed our plan, seized
opportunities and accomplished what we set out to do
– position the company’s portfolio to deliver long-term
sustainable shareholder value.
Within each of our four strategic cornerstones, we made
tremendous progress. We delivered leading onshore well
results, advanced our Eastern Mediterranean project,
strengthened the portfolio and
improved our financial
capability. This past year, we continued our focus on
allocating capital
to
the highest-return, high-margin
TRANSFORMATIVE YEAR
Throughout the year, we successfully repositioned our
onshore portfolio to focus on the high-return, higher-
margin DJ Basin, Delaware Basin and Eagle Ford Shale and
further fortified our balance sheet by divesting non-core
assets. This included the sale of our Marcellus Shale assets to
focus on liquids-rich investment opportunities. A noteworthy
achievement for the year was the acquisition and successful
integration of Clayton Williams Energy, which significantly
increased Noble Energy’s leading position in the Southern
Delaware Basin.
In addition to strengthening and expanding our U.S.
opportunities.
While we have seen unprece-
dented shifts
in energy
industry
dynamics over recent years, our
corporate strategy and premier
portfolio are built
to adapt
to
commodity cycles and deliver strong
returns.
This
year marked
the
85th
anniversary of Noble Energy and
while we look to the future, it’s
important to recognize how far we
As the company has grown into
a leading independent energy
producer, we remain guided by
our core values and unwavering
onshore portfolio, we sanctioned,
commenced development of and
significantly progressed our next
world-class Eastern Mediterranean
project – Leviathan – which will
generate natural gas margins rivaling
the best U.S. onshore oil areas and
a substantial, dependable cash flow
respect for communities, land,
stream for decades to come.
and protecting natural resources.
ACHIEVING OPERATIONAL
AND FINANCIAL GOALS
With our extensive database of
have come since 1932. As the company has grown into a
leading independent energy producer, we remain guided
by our core values and unwavering respect for stakeholders,
communities, land and protecting natural resources. The
combination of our top-tier assets, operational excellence
and financial strength continue to be the foundation of
our success.
horizontal wells drilled and completed across the U.S.,
Noble Energy is at the forefront of advancing drilling and
completion designs in the industry. This past year marked
significant advancements and execution success in our
U.S. onshore program as we set new drilling records, drove
down unit controllable costs and demonstrated
that
we could increase productivity in each of our core areas.
Utilizing superior technology, our advanced analytics arm
us with real-time information and enable rapid well design
modifications. With a sharp focus on continuous improvement
FOCUSED ON DRIVING
SUSTAINABLE SHAREHOLDER VALUE
and innovation, we anticipate even greater drilling and
completion efficiencies in 2018 and beyond.
We have a differential opportunity to realize value through our
premier upstream and midstream assets in the Delaware and
DJ Basins. Notably, the substantial ramp-up in cash flows and
volumes from our high-margin U.S. onshore assets reflects
Looking ahead, Noble Energy is executing a solid strategy and
working to deliver superior results for all stakeholders. To drive
shareholder value, we have been at the forefront of aligning
our compensation incentive plans with shareholder interests.
We will continue to create value by further developing our
high-return, high-margin U.S. onshore assets and supplying
natural gas from the Eastern Mediterranean to meet the
the exceptional performance we
delivered. Our midstream assets
provide
tremendous operational
advantages and we demonstrated
the value with our inaugural drop
down from Noble Energy to Noble
Midstream Partners LP in 2017.
ENVIRONMENTAL, SOCIAL AND
GOVERNANCE LEADERSHIP
At Noble Energy, we are committed
to
corporate
responsibility
in
all we do. For six years now, we
have continued to enhance our
ever-growing
regional demand.
Durability and
the geographic
diversity of our portfolio support the
strategy, investment decisions and
commitment to our core business.
Our
asset quality, unmatched
operational excellence and robust
financial strength provide a clear
line of sight to top-tier cash flow
growth over
the next
several
years. Our objective is to deliver
corporate returns that will retain
and attract
investors across all
disclosures on environment, safety, people, communities,
sectors. Our board recently affirmed our commitment
transparency and governance in our annual Sustainability
to enhancing and accelerating shareholder value with
Report. To further our commitment to our communities, this
approval of a share repurchase program and we anticipate
year marked our inaugural Global Day of Caring, during which
dividend growth based on our expected cash flow expansion.
nearly 1,000 Noble Energy employees supported the needs
of local communities across the globe. As part of this event,
our volunteer efforts in the Houston area amplified our recent
financial contributions to help our hometown recover from
Hurricane Harvey.
Exceptional safety performance is core to our business
and we are once again proud of our efforts. Among many
notable achievements, we set a new record for consecutive
MOVING TOWARDS THE FUTURE
Today, Noble Energy is stronger than ever, with diverse assets
that enable us to deliver long-term value. I would like to
thank everyone on the talented Noble Energy team, whose
contributions allow us to create that value for our most
important constituents: our shareholders, business partners
and employees. I look forward to our journey together
and appreciate your continued trust and confidence in
days without a recordable safety incident across our global
our company.
upstream operations.
Regarding governance, the Noble Energy board of directors
plays a key role in the oversight of the company’s business and
strategy. The board’s Corporate Governance and Nominating
Committee is dedicated to bringing additional insight to our
board and ensuring it remains best equipped to meet the
challenges of the fast-moving global business environment
in which we operate. In October, the board welcomed
Holli C. Ladhani as a director. She brings invaluable executive
leadership and expertise in energy services and finance.
David L. Stover
Chairman, President and CEO
Exceptional Portfolio
Delaware
Basin
p Strong oil-rich
position
p 2017 Sales Volumes:
26 MBoe/d
Gulf of Mexico
p Proven track record
p 2017 Sales Volumes:
26 MBoe/d
Israel
p Doubling gross gas
regional deliverability
p 2017 Sales Volumes:
46 MBoe/d
Equatorial
Guinea
p Maximizing production
p 2017 Sales Volumes:
65 MBoe/d
DJ Basin
p Maximizing operational
efficiencies
p 2017 Sales Volumes:
110 MBoe/d
Eagle Ford
Shale
p Substanstial cash flow
p 2017 Sales Volumes:
70 MBoe/d
Reflects currently producing assets
Transformative Year
Excludes Marcellus Shale sales volumes prior to divestment in June 2017
Financial Results
2017
2016
2015
2014
2013
686
7,680
1,965
195
1,118
381
49.73
3.01
$
$
$
$
$
$
$
$
552
5,308
1,437
186
1,397
420
40.39
2.42
$
$
$
$
$
$
$
$
496
5,549
1,421
158
1,187
355
45.00
2.44
$
$
$
$
$
$
$
$
432
5,833
1,404
133
992
298
91.58
3.38
$
$
$
$
$
$
$
$
435
5,828
1,406
123
901
273
100.29
2.97
2017
2016
2015
2014
2013
4,256
(1,118)
(2.38)
469
0.40
1,951
3,249
21,476
$
6,859
$
10,619
39%
$
$
$
$
$
$
$
$
$
3,491
(998)
(2.32)
430
0.40
1,351
1,339
21,011
7,114
9,600
43%
$
$
$
$
$
$
$
3,183
(2,441)
(6.07)
402
0.72
2,062
2,852
24,196
$
$
$
$
$
$
$
5,115
1,214
3.27
367
0.68
3,506
4,883
22,518
$
7,976
$
6,197
$
10,370
$
10,325
43%
38%
$
$
$
$
$
$
$
$
$
5,015
978
2.69
363
0.55
2,937
4,311
19,642
4,843
9,184
35%
$
$
$
$
$
$
$
$
$
$
$
$
OPERATING DATA
Year-end Proved Reserves
Liquids (MMBbls)
Natural Gas (Bcf)
Total (MMBoe)
Sales Volumes from Continuing Operations
Liquids (MBbl/d)1
Natural Gas (MMcf/d)
Total (MBoe/d)
Average Sales Price
Crude Oil and Condensate (per Bbl)
Natural Gas (per Mcf)
FINANCIAL DATA
(In millions, except per share amounts and ratios)
Revenues
Net (Loss) Income Attributable to Noble Energy
Net (Loss) Income per Share Diluted 2
Weighted Average Shares Diluted 2
Cash Dividends per Share2
Net Cash Provided by Operating Activities
Capital Expenditures 3
Total Assets
Total Debt
Shareholders’ Equity
Total Debt-to-Book-Capital Ratio
1 Includes equity method volumes
2 Amounts adjusted for the 2-for-1 stock split which occurred in 2013
3 Represents Noble Energy-funded expenditures, excludes capital lease accruals and corporate acquisitions
Table of Contents
Index to Financial Statements
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number: 001-07964
NOBLE ENERGY, INC.
(Exact name of registrant as specified in its charter)
Delaware
(State of incorporation)
1001 Noble Energy Way
Houston, Texas
(Address of principal executive offices)
73-0785597
(I.R.S. employer identification number)
77070
(Zip Code)
(281) 872-3100
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Stock, $0.01 par value
Name of each exchange on which registered
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes
No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes
No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.
Yes
No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data
File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files).
Yes
No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained
herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this Form 10-K.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting, or an
emerging growth company. See definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company”, and “emerging
growth company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer
Accelerated filer
Non-accelerated filer
Smaller reporting company
Emerging growth company
(Do not check if a smaller reporting company)
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying
with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
Yes
No
Aggregate market value of Common Stock held by nonaffiliates as of June 30, 2017: $13.8 billion.
Number of shares of Common Stock outstanding as of December 31, 2017: 486,902,907.
Table of Contents
Index to Financial Statements
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive proxy statement for the 2018 Annual Meeting of Stockholders to be held on April 24, 2018, which will
be filed with the Securities and Exchange Commission within 120 days after December 31, 2017, are incorporated by reference into Part III.
Table of Contents
Index to Financial Statements
Items 1. and 2. Business and Properties
Item 1A.
Item 1B.
Item 3.
Item 4.
Risk Factors
Unresolved Staff Comments
Legal Proceedings
Mine Safety Disclosures
TABLE OF CONTENTS
PART I
PART II
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Item 15.
Item 16.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
Selected Financial Data
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Quantitative and Qualitative Disclosures About Market Risk
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
PART III
Directors, Executive Officers and Corporate Governance
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Certain Relationships and Related Transactions, and Director Independence
Principal Accounting Fees and Services
Exhibits, Financial Statement Schedules
Form 10-K Summary
PART IV
2
34
50
50
50
50
53
55
86
88
153
153
153
154
154
154
154
154
154
160
Table of Contents
Index to Financial Statements
Disclosure Regarding Forward-Looking Statements
This Annual Report on Form 10-K and the documents incorporated by reference in this report contain forward-looking
statements within the meaning of the federal securities laws. Forward-looking statements give our current expectations or
forecasts of future events.
These forward-looking statements include, among others, the following:
•
•
•
•
•
•
our growth strategies;
our future results of operations;
our liquidity and ability to finance our exploration and development activities;
our ability to successfully and economically explore for and develop crude oil, natural gas and natural gas liquids
(NGLs) resources;
anticipated trends in our business;
•
• market conditions in the oil and gas industry;
•
the impact of governmental fiscal regulation, including federal, state, local, and foreign host tax regulations, and/or
terms, such as that involving the protection of the environment or marketing of production, as well as other regulations;
our ability to make and integrate acquisitions; and
access to resources.
Forward-looking statements are typically identified by use of terms such as “may,” “will,” “expect,” “believe,” “anticipate,”
“estimate,” “intend,” and similar words, although some forward-looking statements may be expressed differently. These
forward-looking statements are made based upon management’s current plans, expectations, estimates, assumptions and beliefs
concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-
looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the
forward-looking statements. You should consider carefully the statements under Item 1A. Risk Factors and other sections of
this report, which describe factors that could cause our actual results to differ from those set forth in the forward-looking
statements.
Items 1. and 2. Business and Properties
PART I
In this report, unless otherwise indicated or where the context otherwise requires, information includes that of Noble Energy,
Inc. and its subsidiaries (Noble Energy, the Company, we or us). All references to production, sales volumes and reserves
quantities are net to our interest unless otherwise indicated. For a summary of commonly used industry terms and abbreviations
used in this report, see the Glossary, located at the end of this report.
Noble Energy is an independent crude oil and natural gas exploration and production company with a diversified high-quality
portfolio spanning three continents. Founded in 1932, Noble Energy is a Delaware corporation, incorporated in 1969, and has
been publicly traded on the New York Stock Exchange (NYSE) since 1980. We have a unique history of growth, evolving from
a regional crude oil and natural gas producer to a global exploration and production company included in the Standard & Poor's
500 (S&P 500).
Our purpose, Energizing the World, Bettering People's Lives®, reflects our commitment to find and deliver affordable energy
through crude oil, natural gas and NGL exploration and production while living our commitment to contribute to the betterment
of people's lives in the communities in which we operate. We strive to build trust through stakeholder engagement, act on our
values, provide a safe work environment, respect our environment and care for our employees and the communities where we
operate.
Our portfolio of assets is diversified through US and international projects and production mix among crude oil, natural gas,
and NGLs. In particular, our business is focused on both US unconventional basins and certain global offshore conventional
basins. In US onshore unconventional basins, we have demonstrated competence in applying geological, drilling, completion,
and midstream design and operational expertise. In US onshore, we typically apply a major project development concept to an
unconventional basin by utilizing an Integrated Development Plan (IDP) approach. In the global offshore, we have had notable
exploration and major project successes over the past twelve years, which have led to production from numerous offshore
major development projects which have provided long-lived cash flows to our business.
Approximately 70% of our 2018 capital program is allocated to US onshore development, primarily focused on liquids-rich
opportunities in the Denver-Julesburg (DJ) Basin, Delaware Basin and Eagle Ford Shale. Eastern Mediterranean capital
expenditures, including initial development costs associated with the Leviathan project, represent more than 25% of the total.
The remaining portion of our 2018 capital program is designated for exploration for lease acquisition, seismic and other
2
geological analysis in support of future exploration prospects for potential development post 2020, as well as other corporate
activities.
In addition, the majority of our assets are held by production, which allows for further investment and financial flexibility.
Occasional strategic acquisitions of producing or non-producing properties, combined with the periodic divestment of assets,
have allowed us to pursue our objective of a well-positioned and diversified portfolio to maximize strategic value.
Oil and Gas Properties and Activities We search for crude oil and natural gas properties onshore and offshore, and seek to
acquire exploration rights and conduct exploration activities in areas of interest. Our activities include geophysical and
geological evaluation; analysis of commercial, regulatory and political risks; and exploratory and development drilling leading
to production, where appropriate.
Our current portfolio consists primarily of interests in developed and undeveloped crude oil and natural gas leases and
concessions. These properties contribute all of our crude oil, natural gas and NGL production, provide continual investment
opportunities in proved areas, and offer further exploration opportunities. Our new venture areas provide frontier exploration
opportunities, which may result in the establishment of new operational areas in the future. We also own or invest in midstream
assets primarily used in the processing and transportation of our US onshore production. See Midstream - Properties and
Activities, below.
The map below illustrates the locations of our significant crude oil and natural gas exploration and production activities:
Reportable Segments We manage our operations by geographic region and the nature of the products and services we offer.
Our reportable segments include: United States (US onshore and Gulf of Mexico); Eastern Mediterranean (Israel and Cyprus);
West Africa (Equatorial Guinea, Cameroon and Gabon); Other International (Newfoundland, Suriname, and other new
ventures); and Midstream.
The geographical reportable segments are in the business of crude oil and natural gas exploration, development, production,
and acquisition (Oil and Gas Exploration and Production, or E&P). The Midstream reportable segment owns, operates,
develops and acquires domestic midstream infrastructure assets with current focus areas being the DJ and Delaware Basins.
Expenses related to debt, headquarters depreciation and corporate general and administrative cost are recorded at the corporate
level. See Item 8. Financial Statements and Supplementary Data – Note 14. Segment Information.
Development Activities Our development projects have resulted from both exploration success as well as periodic strategic
acquisitions. These projects provide opportunities for growth at attractive financial returns. Each project progresses, as
appropriate, through the various development phases including appraisal, engineering and design, development drilling,
construction and production. While development projects require significant capital investments, typically over a multi-year
period, they are expected to offer sustained cash flows, while on production.
In US onshore, our low production-risk development programs are centered around IDPs and generate efficiencies for upstream
and midstream development. IDPs are generally areas of highly contiguous acreage, typically held by production, that
3
accommodate drilling long lateral wells, and other operational synergies. The approach also benefits from the ability to
accommodate a flexible capital investment program that can be varied in response to changes in the commodity price
environment. We continue to enhance project performance in these areas through technology and operational efficiencies.
Offshore, we engage in long-cycle development projects, such as progressing the first phase of development at the Leviathan
natural gas field, offshore Israel, the largest natural gas discovery in our history. Our development activities are discussed in
more detail in the sections below.
Divestiture and Acquisition Activities We maintain an ongoing portfolio management program. Accordingly, we may
periodically divest assets through asset or equity sales, exchanges or other transactions. During 2017, we closed several
transformative portfolio transactions, demonstrating our continued focus on enhancing profit margins and company returns. We
generated cash of $2.1 billion from asset sales, including divestiture of the Marcellus Shale upstream assets, as well as other
non-strategic US onshore assets. Periodically, we may also engage in acquisitions of additional crude oil or natural gas
properties and related assets through either direct acquisitions of the assets or acquisitions of entities that own the assets. For
example, we completed the acquisition (Clayton Williams Energy Acquisition) of Clayton Williams Energy, Inc. (Clayton
Williams Energy) in 2017 and the merger (Rosetta Merger) of Rosetta Resources Inc (Rosetta) in 2015. See Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources,
Item 8. Financial Statements and Supplementary Data - Note 3. Clayton Williams Energy Acquisition, and Item 8. Financial
Statements and Supplementary Data – Note 4. Acquisitions, Divestitures and Merger.
Exploration Activities We primarily focus on organic growth from exploration and development drilling activities,
concentrating on existing basins or plays where we believe we have strategic competitive advantages or in new basins with
attractive geological potential and the opportunity for attractive financial returns. These advantages are derived from
proprietary seismic data and operational expertise, which we believe will generate superior returns over the oil and gas business
cycle. We have had substantial historic exploration success in the Gulf of Mexico, the Levant Basin offshore Eastern
Mediterranean and the Douala Basin offshore West Africa, resulting in the successful completion of numerous major
development projects. In 2017, we performed limited exploration activities due to the commodity price environment.
Proved Oil and Gas Reserves Proved reserves at December 31, 2017 were as follows:
Reserves Category
Proved Developed
United States
Israel
Equatorial Guinea
Total Proved Developed Reserves
Proved Undeveloped
United States
Israel
Total Proved Undeveloped Reserves
Total Proved Reserves
December 31, 2017
Proved Reserves
Crude Oil
and
Condensate
(MMBbls)
NGLs
Natural
Gas
(MMBbls)
(Bcf)
Total
(MMBoe) (1)
176
3
29
208
243
6
249
457
119
—
11
130
99
—
99
229
983
1,793
411
3,187
838
3,655
4,493
7,680
458
302
108
868
482
615
1,097
1,965
(1) Million barrels oil equivalent. Natural gas is converted on the basis of six Mcf of gas per one barrel of crude oil equivalent. This ratio
reflects an energy content equivalency and not a price or revenue equivalency. Given commodity price disparities, the price for a barrel of
crude oil equivalent for US natural gas and NGLs is 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.
Our proved reserves totaled 1,965 MMBoe as of December 31, 2017 as compared with 1,437 MMBoe as of December 31,
2016. Changes included the following:
•
•
revisions of 135 MMBoe, including positive revisions of 105 MMBoe driven by performance related to the US
onshore horizontal drilling programs and offshore Israel associated with the enhanced geologic modeling across the
Tamar reservoir, as well as an increase of 30 MMBoe driven by positive price revisions;
extensions, discoveries and other additions of 736 MMboe, including additions of 551 MMBoe related to the sanction
of the first phase of development of the Leviathan natural gas project, as well as extensions of 185 MMBoe related to
US onshore horizontal drilling programs due to successful expansion of our extended reach lateral well programs;
•
acquisition of 57 MMBoe primarily related to the Clayton Williams Energy Acquisition;
4
offset by:
•
•
production volumes of 139 MMBoe; and
divestiture of reserves of 261 MMBoe, primarily due to the Marcellus Shale upstream divestiture and other smaller US
onshore divestitures.
Our proved reserves are 48% US and 52% international, and the commodity mix is 35% global liquids (crude oil and NGLs),
50% international natural gas and 15% US natural gas.
See Proved Reserves Disclosures, below, and Item 8. Financial Statements and Supplementary Data – Supplemental Oil and
Gas Information (Unaudited) for further discussion of proved reserves.
Oil and Gas Exploration and Production - Properties and Activities
United States
We have been engaged in crude oil, natural gas and NGL exploration and development activities throughout US onshore since
1932 and in the Gulf of Mexico since 1968. US operations accounted for 72% of 2017 total consolidated sales volumes and
48% of total proved reserves at December 31, 2017. Approximately 45% of the proved reserves in the US is crude oil and
condensate, 32% is natural gas and 23% is NGLs.
Sales volumes and proved reserves estimates for our US operating areas were as follows:
Year Ended December 31, 2017
Sales Volumes
December 31, 2017
Proved Reserves
Crude Oil
&
Condensate
(MBbl/d)
59
17
11
1
21
2
111
NGLs
(MBbl/d)
19
4
28
5
2
—
58
Natural
Gas
(MMcf/d)
193
24
186
174
21
9
607
Total
(MBoe/d)
110
26
70
34
26
4
270
Crude Oil
&
Condensate
(MMBbls)
203
166
29
—
18
3
419
NGLs
(MMBbls)
99
38
79
—
2
—
218
Natural
Gas
(Bcf)
1,094
199
501
—
21
6
1,821
Total
(MMBoe)
484
238
191
—
23
4
940
DJ Basin
Delaware Basin
Eagle Ford Shale
Marcellus Shale (1)
Gulf of Mexico
Other US Onshore
Total
(1) We divested our Marcellus Shale upstream assets in second quarter 2017.
Wells completed in 2017 and productive wells at December 31, 2017 for our US operating areas were as follows:
DJ Basin
Delaware Basin
Eagle Ford Shale
Gulf of Mexico
Other US Onshore
Total
Year Ended
December 31, 2017
Gross Wells
Completed
or Participated in
138
75
47
—
12
272
December 31, 2017
Gross Productive
Wells
6,226
1,898
344
14
1
8,483
5
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Index to Financial Statements
US Onshore
Our US onshore operations are located in proven basins with long-life production profiles. These assets provide low
production-risk drilling opportunities in liquids-rich areas that offer predictable and long-term production and cash flow growth
at attractive financial returns. Locations of our US onshore operations as of December 31, 2017 are shown on the map below:
DJ Basin In 2017, we focused our drilling and development activity in the Wells Ranch and East Pony areas that produce a
high oil mix. The IDP concept allows us to consolidate processing and handling infrastructure across large areas (typically
30,000 to 80,000 acres). Our IDP approach has provided an opportunity to efficiently and economically support production
growth by leveraging infrastructure, such as gas, oil and water, including both fresh and produced water, assets.
2017 Activity Operationally, our focus on drilling longer laterals and obtaining better results from enhanced completions has
led to stronger new well performance. Coupled with expansion of midstream infrastructure and execution of synergies as well
as prudent management of costs, we are delivering enhanced profit margin returns. During the year, we completed 103
horizontal wells and 101 wells initiated production. We also participated in approximately 35 non-operated development wells
during 2017.
As part of ongoing portfolio management, we entered into an agreement to divest approximately 30,200 net acres, the majority
of which were undeveloped, in the Greeley Crescent area of Weld County, Colorado for $608 million. We received proceeds of
$568 million at closing and expect to receive the remaining proceeds in mid-2018. As part of the transaction, all of the acreage
in the Greeley Crescent Bronco IDP remains subject to dedications to Noble Midstream Partners LP (Noble Midstream
Partners) for crude oil gathering, and produced and fresh water services.
Since 2015, we have been working with the State of Colorado to improve emission control systems as required under a joint
consent decree (Consent Decree). Overall compliance with the Consent Decree has resulted in the temporary shut-in and
permanent plugging and abandonment of certain wells, the majority of which are vertical, and associated tank batteries. Costs
associated with these abandonment activities will be incurred over several years.
We exited 2017 with one drilling rig and intend to increase to two rigs in 2018. Our current 2018 development program
contemplates expansion into the Mustang IDP area where we have a large, contiguous acreage position.
Delaware Basin Our Delaware Basin position was significantly transformed in 2017 with the closing of the Clayton Williams
Energy Acquisition on April 24, 2017, adding 71,000 highly contiguous net acres in the core of the Delaware Basin adjacent to
our Reeves County holdings. We also executed strategic leasing initiatives and entered into a bolt-on acquisition, for $295
million, which closed in January 2017, adding additional production near our producing properties and increasing our
6
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Index to Financial Statements
contiguous acreage position in the Reeves County area. As of December 31, 2017, we held approximately 117,000 net acres in
the Delaware Basin.
2017 Activity In 2017, we successfully integrated the Clayton Williams Energy assets and initiated execution of the Delaware
Basin IDP with a focus on long laterals, pad drilling, multi-zone completions and infrastructure development. As demonstrated
in the DJ Basin, our IDP approach provides an opportunity to more efficiently and economically develop our acreage.
We successfully transformed our 2017 development program's focus from a single well development approach to an IDP to
capture the full resource potential for the Delaware Basin. This was achieved with eight pads that developed multiple zones
within the Wolfcamp A formation zone, including two pads that successfully included the shallower 3rd Bone Springs
zone. With successful wells in the deeper Wolfcamp zones, as well as expanded understanding of the resource potential and our
IDP approach, we are well positioned to efficiently and economically develop our acreage over future years.
We began 2017 with three drilling rigs and exited the year with six drilling rigs. During the year, we completed 45 wells and
commenced production on 44 wells, of which 23 were multi-zone pads. We also participated in approximately 30 non-operated
development wells during 2017. In addition, we added two central gathering facilities (CGFs).
For 2018, we will continue asset development through long laterals, pad drilling, multi-zone development and an infrastructure
build-out initiative that will include an additional three CGFs.
Eagle Ford Shale We hold approximately 35,000 net acres located in the highly prolific liquids-rich area of the play,
including producing assets in Webb and Dimmit counties. Since acquiring these assets, we have continued to apply IDP
learnings and enhancements to optimize development of these assets, including optimizing drilling and completion designs
through testing varying clusters per stage, lateral lengths, and proppant quantities to increase investment efficiency. We have
also focused on testing co-development of both the Upper and Lower Eagle Ford formation zones utilizing our IDP approach.
2017 Activity Our 2017 capital program was focused within Webb and Dimmit counties where we operated up to two drilling
rigs, completed 47 horizontal wells and commenced production on 49 horizontal wells. All wells drilled during 2017 were on
multi-well pads leveraging centralized infrastructure. We also sold certain assets located in Gonzales and DeWitt counties,
where we had not engaged in drilling activities since the completion of the merger (Rosetta Merger) with Rosetta Resources
Inc. (Rosetta) and received proceeds of $45 million.
We exited 2017 with a two rig drilling program. Our capital program in 2018 focuses on developing the Upper and Lower
Eagle Ford formation zones within the Gates Ranch area.
Marcellus Shale On June 28, 2017, we closed the sale of the Marcellus Shale upstream assets, receiving net proceeds of $1.0
billion and recorded a loss on sale of $2.38 billion. The divestment enables us to further focus our organization on our highest-
return areas that are expected to deliver production and cash flow growth.
See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital
Resources and Item 8. Financial Statements and Supplementary Data – Note 4. Acquisitions, Divestitures and Merger.
7
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Gulf of Mexico Locations of our operations in the Gulf of Mexico as of December 31, 2017 are shown on the map below:
We have several producing fields and an inventory of identified prospects, which are a combination of both high impact subsalt
prospects and smaller tie-back opportunities. These prospects are subject to an ongoing technical maturation process and may
or may not emerge as drillable options.
We currently hold leases on approximately 63 deepwater blocks, representing approximately 52,000 net developed acres and
approximately 171,000 net undeveloped acres. We are the operator on nearly 80% of our leases.
Subsequent Event On February 15, 2018, we announced the Company signed a definitive agreement to sell its assets in the
Gulf of Mexico. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations –
Executive Overview and Item 8. Financial Statements and Supplementary Data – Note 4. Acquisitions, Divestitures and
Merger.
2017 Activity Our activity in 2017 primarily focused on optimizing production and progressing our Katmai project. See
Offshore Producing Properties and Update to Gulf of Mexico Major Projects, below.
During 2017, we completed our geological evaluation of certain leases and determined that several leases, representing $60
million of undeveloped leasehold cost, should be impaired and expensed.
We have remaining capitalized undeveloped leasehold cost of approximately $44 million related to prospects that have not yet
been drilled. Leases representing over 60% of this cost are scheduled to expire over the years 2018 to 2020. In addition, some
leases may become impaired if production is not established or should we not take action to extend the terms of the leases. As a
result of our exploration activities, capitalized undeveloped leasehold costs could become impaired. See Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations – Operating Outlook – Potential for Future
Impairments.
Offshore Producing Properties
Gunflint (Mississippi Canyon Block 948; 31% operated working interest) Gunflint is a 2008 crude oil discovery, utilizing a
two-well subsea tieback to the Gulfstar 1 spar platform. Production commenced in July 2016 and the development contributed
7 MBoe/d of sales volumes in 2017.
Rio Grande Development including Big Bend (Mississippi Canyon Block 698; 54% operated working interest) and Dantzler
(Mississippi Canyon Block 782; 45% operated working interest) The Rio Grande crude oil development project consists of a
single producing well from Big Bend, a 2012 crude oil discovery, and two producing wells from Dantzler, a 2013 crude oil
discovery, flowing to the Thunder Hawk platform for which we assumed operatorship in 2016. The Rio Grande development
commenced production in October 2015 and contributed an average of 12 MBoe/d of sales volumes in 2017.
Galapagos Development Project including Isabela (Mississippi Canyon Block 562; 33.33% non-operated working interest),
Santa Cruz (Mississippi Canyon Blocks 519/563; 23.25% operated working interest) and Santiago (Mississippi Canyon Block
8
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Index to Financial Statements
519; 23.25% operated working interest) The Galapagos crude oil development project consists of Isabela, a 2007 discovery,
Santa Cruz, a 2009 discovery, and Santiago, a 2011 discovery. The Galapagos development began producing in 2012 and is
connected to existing infrastructure through subsea tiebacks. A well stimulation commenced in the fourth quarter of 2017 to
enhance recovery. The Galapagos project contributed an average of 4 MBoe/d of sales volumes in 2017.
Swordfish (Viosca Knoll Blocks 917; 961 and 962; 85% operated working interest) Swordfish is a 2001 crude oil discovery
and began producing in 2005. The Swordfish project currently includes two producing wells flowing to the Neptune Spar, our
100%-owned floating offshore production platform, and contributed an average of 3 MBoe/d of sales volumes in 2017. We
currently plan to begin abandonment activities in 2019.
Ticonderoga (Green Canyon Block 768; 50% non-operated working interest) Ticonderoga is a 2004 crude oil discovery and
began producing in 2006. The project currently includes two producing wells, which contributed an average of 1 MBoe/d of
sales volumes in 2017. These properties are connected to existing infrastructure through subsea tiebacks.
Update to Gulf of Mexico Major Projects
Katmai (Green Canyon Block 40; 50% operated working interest) During 2014, we announced successful final well results at
the Katmai exploratory well. Katmai was drilled to a total depth of 27,900 feet in 2,100 feet of water. Wireline logging data
indicated a total of 154 net feet of crude oil pay discovered in multiple reservoirs, including 117 net feet in Middle Miocene and
37 net feet in Lower Miocene reservoirs. In 2016, we spud our Katmai 2 appraisal well (38% operated working interest),
located in Green Canyon Block 39, and encountered high pressure in the untested fault block. In response, we temporarily
abandoned the well and are assessing plans to complete appraisal as well as development scenarios for the Katmai project.
Troubadour (Mississippi Canyon Block 699; 60% operated working interest) Troubadour was a 2013 natural gas discovery. In
2017, we determined that the asset was impaired in the current forward outlook for natural gas prices and development
scenarios, and charged $63 million to impairment of oil and gas properties and $5 million to undeveloped leasehold impairment
expense.
Regulatory Environment Various federal agencies overseeing certain of our activities in the Gulf of Mexico have adopted new
regulations and are considering others. See Regulations - US Offshore Regulatory Developments below, and Item 1A. Risk
Factors.
International
Our international business focuses on offshore opportunities in a number of countries and diversifies our portfolio.
Development projects in the Eastern Mediterranean and West Africa have contributed substantially to our production and cash
flow growth over the last decade. Previous exploration successes in these areas have also identified additional multiple major
development projects that have the potential to contribute to long-term production and cash flow growth in the future.
During 2017, we progressed development of offshore Israel assets by completing the Tamar 8 development well and
commencing drilling activities for the Leviathan 5 development well. In addition, we advanced our Eastern Mediterranean
regional natural gas export opportunities by progressing multiple natural gas sales and purchase agreements (GSPAs). See
Eastern Mediterranean (Israel and Cyprus) and West Africa (Equatorial Guinea, Cameroon and Gabon), below.
Operations in Equatorial Guinea, Cameroon, Gabon, Cyprus, and Suriname are conducted in accordance with the terms of
Production Sharing Contracts (PSCs). Operations in Israel, Newfoundland (Canada) and other foreign locations are conducted
in accordance with concession agreements, permits or licenses. See Item 1A. Risk Factors.
9
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Index to Financial Statements
Sales volumes and proved reserves estimates for our international operating areas were as follows:
Year Ended December 31, 2017
Sales Volumes
December 31, 2017
Proved Reserves
Crude Oil
&
Condensate
(MBbl/d)
NGLs
(MBbl/d)
Natural
Gas
(MMcf/d)
Total
(MBoe/d)
Crude Oil
&
Condensate
(MMBbls)
NGLs
(MMBbls)
Natural
Gas (1)
(Bcf)
Total
(MMBoe)
International
Israel
Equatorial Guinea
Total International
Equity Investee
Total
Equity Investee Share of Methanol Sales (MMgal)
—
—
—
6
6
—
18
18
2
20
272
239
511
—
511
46
57
103
8
111
163
9
29
38
—
38
—
11
11
—
11
5,448
411
5,859
—
5,859
917
108
1,025
—
1,025
(1) Includes 3.3 Tcf proved undeveloped reserves related to initial Leviathan field development offshore Israel.
Wells completed in 2017 and productive wells at December 31, 2017 in our international operating areas were as follows:
International
Israel
Equatorial Guinea
Total International
Year Ended December 31, 2017
Gross Wells Completed
or Participated in (1)
December 31, 2017
Gross Productive
Wells
1
—
1
7
28
35
(1) Excludes the Araku-1 exploration well, offshore Suriname.
Eastern Mediterranean (Israel and Cyprus) One of our operating areas is the Eastern Mediterranean, where we have
identified the existence of substantial natural gas resources since we obtained our first exploration license offshore Israel in
1998.
Israel, the only producing country in our Eastern Mediterranean area, contributed an average of 272 MMcf/d of natural gas
sales volumes in 2017, representing approximately 12% of total consolidated sales volumes, primarily from the Tamar field.
With the addition of proved undeveloped reserves associated with Leviathan field development in 2017, Israel represented
approximately 47% of total proved reserves at December 31, 2017. Our leasehold position in the Eastern Mediterranean at
December 31, 2017, included four leases and three licenses operated offshore Israel. Offshore Cyprus, we operate under the
terms of a PSC.
At December 31, 2017, the Eastern Mediterranean position included approximately 78,000 net developed acres and 116,000 net
undeveloped acres located between 10 and 90 miles offshore Israel in water depths ranging from 700 feet to 6,500 feet. The
license offshore Cyprus covers approximately 33,000 net undeveloped acres adjacent to our Israel acreage.
10
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Index to Financial Statements
Locations of our operations in the Eastern Mediterranean as of December 31, 2017 are shown below:
Offshore Israel Noble Energy and our partners have delivered reliable and affordable natural gas to Israeli citizens for over a
decade. During this time, we have delivered approximately 2.3 Tcf, gross, of natural gas to Israeli customers, including the
Israel Electric Corporation (IEC), the largest supplier of electricity in the country.
We are the first company to construct, operate and produce from a major natural gas development project offshore Israel. Our
Mari-B discovery provided the country with its first supply of domestic natural gas in 2004. In 2009, we discovered the Tamar
field, another substantial natural gas resource. To maintain and increase natural gas supply to Israel, we developed the Tamar
field with a discovery to production cycle time of approximately four years, which is exceptionally fast by global industry
standards for an offshore natural gas project of this magnitude and complexity.
In 2010, we discovered the Leviathan field, our largest natural gas discovery to date. The quantity of discovered natural gas
resources at Tamar and Leviathan positions Israel to meet domestic needs for decades and to become a significant natural gas
exporter. Multiple natural gas customers exist in the region, and Israel’s domestic demand is predicted to continue to grow over
the next decade, primarily driven by increased use of natural gas over coal to fuel electric power generation. During 2017,
growth in power, industrial and residential demand in Israel and first exports to Jordan, coupled with almost 100% asset
uptime, enabled us to set a new sales volume record of 956 MMcfe/d, gross, from fields offshore Israel.
In addition to our natural gas discoveries, the Levant Basin is prospective for crude oil discoveries at greater depths. We
conducted preliminary exploration activities in 2012 and are analyzing the potential for future exploration.
Domestic Natural Gas Demand As the Israeli economy continues to grow, the demand for natural gas used primarily for
electricity generation is also expected to grow. Demand for natural gas in the industrial sector, including refineries, chemical,
desalination, cement and other plants, as well as residential uses, is also increasing. These sectors are gaining confidence that a
long-term supply of affordable natural gas will be available and are now investing the capital necessary to convert facilities and
infrastructure to use natural gas. In addition, government requirements for emissions reductions have also driven incremental
demand for natural gas beginning in 2016. We have executed numerous GSPAs with domestic customers. See International
Marketing Activities and Delivery and Firm Transportation Commitments, below.
Regional Demand and Exports The Eastern Mediterranean presents an opportunity to match our affordable, abundant supply
of natural gas with a substantially undersupplied regional market, including customers in Jordan and Egypt. With the Tamar
field online providing reliable production, and the development of the Leviathan field progressing, we are well positioned to
supply natural gas to the region for many years.
11
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Index to Financial Statements
Israel Natural Gas Projects
Tamar Natural Gas Project (32.5% operated working interest) The Tamar project began production in March 2013 and has
peak flow rates of approximately 1.1 Bcf/d, gross, to support seasonal high demand periods. In 2015, we completed the Tamar
compression project, which expanded field production capacity by adding compression at the Ashdod onshore terminal (AOT)
and in 2017, we completed and commenced production from the Tamar 8 development well. The Tamar 8 well increases supply
reliability as domestic demand for natural gas continues to grow.
In 2017, we installed subsea equipment to allow for future tie-back of our 2013 Tamar Southwest discovery into the Tamar
platform and other existing infrastructure. We continue to work with the Government of Israel to obtain regulatory approval of
the development plan, which would help reinforce the reliability for the Tamar project and support increased customer demand.
We are also assessing the possibility for expansion of the Tamar project. The project would expand field deliverability from the
current capacity level of approximately 1.2 Bcf/d to up to approximately 2.1 Bcf/d, a quantity that would allow for additional
regional export. Expansion would include a third flow line component and additional producing wells. Timing of project
sanction is dependent upon progress relating to domestic and regional marketing efforts of these resources as well as regulatory
approvals from respective governments.
The Israel Natural Gas Framework (Framework) provides for reduction in our ownership interest in the Tamar and Dalit fields
from 36% to 25% by year-end 2021. In 2016, we divested 3.5% of our interest in these respective fields, partially fulfilling this
commitment required by the Framework. Further, on January 29, 2018, we signed a definitive agreement to divest a 7.5%
working interest in these respective fields to Tamar Petroleum Ltd (TASE: TMRP). See Item 8. Financial Statements and
Supplementary Data – Note. 4. Acquisitions, Divestitures and Merger.
Leviathan Natural Gas Project (39.66% operated working interest) In early 2017, we announced project sanction of the
Leviathan natural gas project and recorded initial proved reserves of 3.3 Tcf (551 MMBoe) associated with the first phase of
development. The first phase of development of the Leviathan field provides 1.2 Bcf/d of production capacity and consists of
four wells, a subsea production system and a shallow-water processing platform, with a connection to an onshore valve station
and the Israel Natural Gas Lines (INGL) pipeline network. We expect our share of development costs to total approximately
$1.5 billion and to be funded from our share of cash flows from the Tamar asset and expected proceeds to be received from the
sell-down of our ownership interest in Tamar as noted above. In addition, we have the ability to borrow under the Leviathan
Term Loan Facility (defined below). As we progress the first phase of development, we have included volume capacity
expansion optionality on the Leviathan platform to allow for cost effective expansion to meet growing regional natural gas
demand.
During 2017, we commenced drilling and continued detailed design and engineering activities and fabrication of onshore
facilities, topsides, jacket and subsea equipment. We will continue drilling activities and commence well completions in 2018
as we progress the project towards first gas sales by the end of 2019. As of December 31, 2017, the project remained within
budget and on schedule at approximately 35% complete, with all critical path equipment and major contracts secured.
The marketing and development of natural gas from this asset is intended to serve both domestic demand and regional export.
We are actively engaged in natural gas marketing activities and have progressed multiple GSPAs totaling up to approximately
525 MMcf/d, gross (approximately 208 MMcf/d, net) of natural gas from the Leviathan field.
Our largest Leviathan GSPA, with the National Electric Power Company Ltd. (NEPCO) of Jordan, provides for sales of natural
gas intended for consumption in power production facilities over a 15-year period. Sales to NEPCO are anticipated to
commence at field startup. We continue to market natural gas from the Leviathan field toward realizing full utilization of the
1.2 Bcf/d of production capacity. See Israel Natural Gas Framework and Regulatory Environment, below.
Alon D License In August 2017, the Petroleum Commissioner of Israel granted us a 32-month extension of the Alon D license
(47.059% operated working interest) to drill an exploration well. We are performing geologic and environmental studies
necessary to progress the prospect to an investment decision.
Other Discoveries Offshore Israel Our development plan for the Dalit field (32.5% operated working interest), a 2009 natural
gas discovery, was approved by the Government of Israel. Development includes a tieback to the Tamar platform. We are also
analyzing 3D seismic data to evaluate the additional potential of the area, including the possible existence of hydrocarbons at
deeper intervals.
Asset Impairments No impairment expense was recorded during 2017. During 2016, we recorded impairment expense of $88
million related to certain Leviathan field development concepts which were not selected. During 2015, we recorded impairment
expense of $36 million, primarily due to an increase in field abandonment costs. See Item 8. Financial Statements and
Supplementary Data – Note 5. Asset Impairments.
Israel Natural Gas Framework and Regulatory Environment We are subject to certain fiscal, antitrust and other regulatory
challenges in Israel. These challenges have been addressed with the enactment of the Framework by the Government of Israel.
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See Regulations – Israel Regulatory Environment and Item 1A. Risk Factors – Our Eastern Mediterranean discoveries bear
certain geopolitical, regulatory, financial and technical challenges that could adversely impact our ability to monetize these
natural gas assets.
Cyprus Natural Gas Project (Offshore Cyprus) During fourth quarter 2015, we entered into a farm-out agreement with a
partner for a 35% interest in Block 12, which includes the Aphrodite natural gas discovery, for $171 million. We received initial
proceeds of $131 million related to the farm-out agreement in 2016 and received the remaining consideration, subject to post-
close adjustments, in January 2017. We continue to operate with a 35% interest. As part of the farm-out process, we negotiated
a waiver of our remaining exploration well obligation.
In September 2017, we submitted an updated development plan to the Government of Cyprus. We continue to work with the
Government of Cyprus to obtain approval of the development plan and the issuance of an Exploitation License for the
Aphrodite field. Receiving an Exploitation License, in conjunction with securing markets for Aphrodite natural gas, will allow
us and our partners to perform the necessary FEED studies and progress the project to final investment decision. In preparation
for FEED, we and our partners are currently performing preliminary engineering and design (pre-FEED) for the potential
development of the Aphrodite field that, as currently planned, would deliver natural gas to regional customers. During 2017, we
progressed capital project cost improvements and continued regional natural gas marketing efforts.
West Africa (Equatorial Guinea, Cameroon and Gabon) West Africa is one of our operating areas and includes the Alba
field, Block O and Block I offshore Equatorial Guinea, the YoYo PSC, offshore Cameroon, and one block offshore Gabon. In
West Africa, our interests can be burdened by overriding royalty interests and/or other government interests. As such, our
working interests may differ from our revenue interests. Equatorial Guinea is currently our only producing country in our West
Africa segment and, excluding the impact of equity investees, Equatorial Guinea contributed an average of 57 MBoe/d of sales
volumes in 2017 and represented approximately 15% of total consolidated sales volumes. At December 31, 2017, Equatorial
Guinea represented approximately 5% of total proved reserves. We held approximately 118,000 net developed acres and 30,000
net undeveloped acres in Equatorial Guinea, 168,000 net undeveloped acres in Cameroon, and 403,000 net undeveloped acres
in Gabon at December 31, 2017.
Locations of our upstream operations in Equatorial Guinea and Cameroon, as of December 31, 2017 are shown on the map
below:
Aseng Field Aseng is an oil field on Block I (40% operated working interest, 38% revenue interest), offshore Equatorial
Guinea, which began producing in 2011. The development includes five horizontal producing wells flowing to the Aseng
floating production, storage and offloading vessel (FPSO) where the crude oil is stored until sold, and natural gas and water are
reinjected into the reservoir to maintain pressure and maximize crude oil recoveries. During 2017, the Aseng field produced
approximately 7 MBoe/d, net.
13
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Index to Financial Statements
The Aseng FPSO is designed to act as a crude oil production hub, as well as a liquids storage and offloading facility, with
capabilities to support future subsea oil field developments in the area. It also has the ability to process and store condensate
from natural gas condensate fields in the area, the first of which is Alen. Since it first came online, the Aseng field has
maintained reliable performance, averaging over 99% production uptime and, as of December 31, 2017, has produced 89
MMBbls of cumulative gross crude oil production.
Alen Field Alen is a natural gas and condensate field primarily on Block O (51% operated working interest, 45% revenue
interest), offshore Equatorial Guinea, which includes three production wells and three natural gas injection wells connected to a
production platform that utilizes the Aseng FPSO for storage and offloading. Alen has been producing since 2013 and produced
approximately 4 MBoe/d, net, during 2017. As of December 31, 2017, Alen has produced over 33 MMBbls of cumulative gross
condensate production.
The Alen platform is expected to be utilized in our natural gas monetization efforts. See West Africa Natural Gas Monetization,
below.
In October 2017, we executed a unitization agreement on the Alen field with our partners and the Government of Equatorial
Guinea. The agreement was between Block O and Block I interest owners. We expect the impact on our allocated future sales
volumes to be de minimis.
Alba Field Alba is a natural gas and condensate field located offshore Equatorial Guinea (33% non-operated working interest,
32% revenue interest), which has been producing since 1991. Operations include the Alba field and related production and
condensate storage facilities, a liquefied petroleum gas (LPG) processing plant where additional condensate is extracted along
with LPGs, and a methanol plant capable of producing up to 3,100 gross metric tons per day of methanol. The LPG processing
plant and the methanol plant are located on Bioko Island, Equatorial Guinea. During 2017, Alba field sales volumes totaled 54
MBoe/d, net, reflecting 46 MBoe/d attributable to total sales volumes and 8 MBoe/d attributable to an equity investee.
In April 2017, we executed a unitization agreement on the Alba field with our partner and the Government of Equatorial
Guinea. The agreement was between Alba Block and Block D interest owners. As a result of the unitization, our revenue
interest going forward changed from 34% to 32%, and our non-operated working interest changed from 35% to 33%. As
anticipated, our 2017 sales volumes from the Alba field were lower as a result of the unitization, and the impact on our proved
reserves was de minimis. We expect the impact on our allocated future sales volumes to be de minimis.
We sell our share of primary condensate produced in the Alba field under short-term contracts at market-based prices. We sell
our share of natural gas production from the Alba field to the LPG plant, the methanol plant and an unaffiliated liquefied
natural gas (LNG) plant. The LPG plant is owned by Alba Plant LLC (Alba Plant), in which we have a 28% interest. The
methanol plant is owned by Atlantic Methanol Production Company, LLC (AMPCO), in which we have a 45% interest.
AMPCO purchases natural gas from the Alba field under a contract that runs through 2026 and subsequently markets the
produced methanol primarily to customers in the US and Europe. Alba Plant sells its LPG products and secondary condensate
at our marine terminal at prevailing market prices.
We account for both Alba Plant and AMPCO as equity method investments and present our share of income as a component of
revenues. We consider these equity method investments essential components of our business as well as necessary and integral
elements of our value chain in support of ongoing operations in our West Africa operating area. Our Alba asset teams are fully
engaged in operational and financial decisions and exert significant influence in the monetization of the Alba field and Alba
Plant. We hold a voting position on AMPCO's leadership team through AMPCO's management committee, and our asset teams
influence decisions regarding capital investments, budgets, turnarounds, maintenance and other project matters.
West Africa Natural Gas Monetization We continue our efforts to monetize the significant natural gas resources represented by
our discoveries offshore West Africa, including our 2007 Yolanda discovery (Block I), the YoYo discovery, offshore Cameroon,
as well as natural gas from our Aseng and Alen fields.
As part of our monetization efforts, a natural gas development team has been working with local governments to evaluate
natural gas monetization concepts. After analyzing existing infrastructure, including the Alen platform and other facilities, we
believe these assets can be efficiently modified and retrofitted to allow for future commercialization of natural gas. Leveraging
existing assets for the development of natural gas minimizes future capital expenditures while providing advantageous financial
returns.
Cameroon We have an interest in approximately 168,000 undeveloped acres offshore Cameroon in our YoYo PSC (100%
operated working interest). The YoYo-1 exploratory well was drilled in 2007, discovering natural gas and condensate. We are
working with the government of Cameroon to evaluate natural gas development options, which will provide a more robust
framework directly related to oil and gas operational activities. In June 2017, we converted our mining concession license for
the YoYo block into a PSC.
Offshore Gabon We are the operator of Block Doukou Dak (60% working interest), an undeveloped, deepwater area, covering
approximately 671,000 gross acres. Our exploration commitment includes an obligation for 3D seismic, which was acquired
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Index to Financial Statements
and processed throughout 2016 and the first half of 2017. We received the final product mid-year 2017 and are currently
evaluating the seismic data results.
See also Item 8. Financial Statements and Supplementary Data – Note 6. Capitalized Exploratory Well Costs and Undeveloped
Leasehold Costs.
Other International
Other international operations include the following:
Offshore Newfoundland (Canada) In November 2016, we acquired a non-operated 25% working interest in exploration
parcels (blocks) 3, 4 and 8, and a non-operated 40% working interest in exploration parcel (block) 10. BP Canada Energy
Group ULC is the operator of the blocks. We have acquired 3D seismic data which will allow us to assess the economic
viability of this exploration prospect.
Offshore Suriname We hold a non-operated 20% working interest in Block 54 offshore Suriname in the Atlantic Ocean. In
October 2017, our partner spud the Araku-1exploration well and subsequently plugged and abandoned the well. As a result, we
recorded dry hole expense of $7 million and are currently analyzing the well results to update modeling of the basin and review
further prospectivity. See Note 5. Asset Impairments.
Offshore Falkland Islands In 2016, following completion of our geological assessment, we exited all licenses, excluding the
PL-001 which contains the Rhea prospect. The exit resulted in a $25 million undeveloped leasehold impairment expense. As of
December 31, 2017, there is no remaining net book value associated with the assets.
North Sea The non-operated MacCulloch field is currently undergoing decommissioning activities. Due to its size and
location, field abandonment is a multi-year process, requiring several phases. Therefore, our share of estimated field
abandonment costs, recorded as an asset retirement obligation, may change over time. For example, during 2017, the operator
of the MacCulloch field notified working interest owners that the scope and magnitude of decommissioning activities has been
revised downward, resulting in lower projected field abandonment costs. As such, we recorded a revision of $42 million in
2017 that decreased our estimated asset retirement obligation for the remediation project. The discounted obligation totaled 44
million at December 31, 2017. We will continue to monitor the status and costs of the project and will adjust our estimate
accordingly.
Midstream – Properties and Activities
We continue to develop our Midstream business, which includes gathering, treating, and transportation assets as well as water-
related infrastructure, including fresh water delivery and produced water disposal assets, that support our upstream operations.
Our Midstream assets are strategically located with our exploration and production activities in the DJ and Delaware Basins.
These assets also provide services to third party customers.
Our Midstream operations include those of Noble Midstream Partners, a publicly traded consolidated subsidiary and limited
partnership that owns, operates, develops, and acquires a wide range of domestic midstream infrastructure assets. Noble
Midstream Partners is a fee-based, growth-oriented Delaware master limited partnership formed in December 2014 organized
in a development company structure. At December 31, 2017, our ownership interest in Noble Midstream Partners consisted of a
45.5% limited partner interest, the entire non-economic general partner interest, and all of the incentive distribution rights.
On September 20, 2016, Noble Midstream Partners completed its initial public offering of common units, which provided
access to capital markets to support funding of our US onshore midstream investment program.
The following diagram depicts our organizational structure as of December 31, 2017. Development companies identified in red
and blue indicate the location of the assets as either in the DJ Basin or Delaware Basin, respectively.
15
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Index to Financial Statements
Advantage Joint Venture In April 2017, Noble Midstream Partners, along with its partner, Plains Pipeline, L.P., formed the
Advantage joint venture (Advantage Joint Venture) and subsequently completed the acquisition of Advantage Pipeline L.L.C.
(Advantage Pipeline). Noble Midstream Partners serves as the operator of the Advantage Pipeline System, which includes a 70-
mile crude oil pipeline (Advantage Delaware Basin Pipeline) in the Delaware Basin from Reeves County, Texas to Crane
County, Texas with 150 MBbls per day of capacity (expandable to over 200 MBbls per day) and 490 MBbls of storage capacity.
Noble Midstream Partners owns a 50% interest in the joint venture.
Asset Contribution On June 26, 2017, Noble Midstream Partners acquired an additional 15% limited partner interest in Blanco
River DevCo LP (Blanco River DevCo), increasing its ownership to 40% of Blanco River DevCo, and acquired the remaining
20% limited partner interest in Colorado River DevCo LP (Colorado River DevCo) from Noble Energy. Blanco River DevCo
holds Noble Midstream Partners’ Delaware Basin in-field gathering dedications for crude oil and produced water gathering
services on approximately 111,000 net acres, with substantially all of the acreage also dedicated for natural gas gathering.
Colorado River DevCo consists of gathering systems across Noble Energy’s Wells Ranch and East Pony development areas in
the DJ Basin.
Black Diamond Gathering and Acquisition of Saddle Butte Pipeline In December 2017, Noble Midstream Partners and
Greenfield Midstream, LLC (Greenfield Midstream) formed an entity, Black Diamond Gathering LLC (Black Diamond
Gathering), to acquire Saddle Butte Rockies Midstream, LLC and affiliates (Saddle Butte). The acquisition includes a large-
scale integrated crude oil gathering system in the DJ Basin, consisting of approximately 160 miles of pipeline in operation and
300 MBbls per day of delivery capacity. Saddle Butte has approximately 141,000, net dedicated acres from six customers under
fixed fee arrangements.
The transaction closed on January 31, 2018, with Noble Midstream Partners funding $319.9 million of the total cash
consideration of $638.5 million. Noble Midstream Partners received a 54.4% equity ownership and Greenfield Midstream will
own the remaining 45.6% of Black Diamond Gathering. Noble Midstream Partners will operate the Saddle Butte system.
Marcellus Shale CONE Gathering Divestiture In late 2017, we announced the signing of a definitive agreement to divest
our 50% interest in CONE Gathering, LLC (CONE Gathering). CONE Gathering owns the general partner of CONE
Midstream Partners LP (CONE Midstream). As of December 31, 2017, the net book value of the assets held by Noble Energy
16
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Index to Financial Statements
was approximately $181 million. In January 2018, we closed the sale of CONE Gathering, receiving cash proceeds of $308
million. We now hold 21.7 million common units representing limited partner interests in CNX Midstream Partners LP (NYSE:
CNXM). As of December 31, 2017, the net book value of the limited partner interests was approximately $70 million.
See Item 8. Financial Statements and Supplementary Data – Note 4. Acquisitions, Divestitures and Merger and Item 8.
Financial Statements and Supplementary Data – Note 7. Equity Method Investments.
Major Construction Projects Our activity in 2017 primarily focused on construction and development of midstream
infrastructure assets, including:
•
•
•
•
•
completion of a produced water expansion project servicing the Wells Ranch IDP area;
completion of crude oil and produced water gathering systems servicing the Greeley Crescent IDP area;
completion of the connection from the CGF in the Delaware Basin to the Advantage Pipeline, which began allowing
crude oil to flow from the completed facility to the Advantage Pipeline in third quarter 2017;
completion of the construction of two CGFs in the Delaware Basin; and
continued construction activities on expansion of our freshwater system servicing the Mustang IDP area and the
commencement of construction of the backbone gathering infrastructure build-out, which is expected to be completed
in early 2018.
In 2018, we expect to continue our midstream investment to focus on the DJ and Delaware Basins to meet the needs of our
upstream operations.
Third Party Sales During 2017, we began providing crude oil and produced water gathering and fresh water delivery services
to an unaffiliated third party in the Greeley Crescent IDP area of the DJ Basin.
Proved Reserves Disclosures
Internal Controls Over Reserves Estimates Our policies and processes regarding internal controls over the recording of reserves
estimates require reserves to be in compliance with the Securities and Exchange Commission (SEC) definitions and guidance and
prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated
by the Society of Petroleum Engineers. Our internal controls over reserves estimates also include the following:
•
•
the Audit Committee of our Board of Directors reviews significant reserves changes on an annual basis;
fields that meet a minimum reserve quantity threshold, newly sanctioned development projects, and certain fields
selected on a rotational basis, which combined represent over 80% of our proved reserves, are audited by Netherland,
Sewell & Associates, Inc. (NSAI), a third-party petroleum consulting firm, on an annual basis; and
• NSAI is engaged by, and has direct access to, the Audit Committee. See Third-Party Reserves Audit, below.
Responsibility for compliance in reserves estimation is delegated to our Corporate Reservoir Engineering group. Qualified
petroleum engineers in our Houston and Denver offices prepare all reserves estimates for our different geographical regions.
These reserves estimates are reviewed and approved by regional management and senior engineering staff with final approval
by the Senior Vice President – Corporate Development and certain other members of senior management.
Our Senior Vice President – Corporate Development oversees our corporate business development, strategic planning, and
reserves departments. He is the technical person primarily responsible for overseeing the preparation of our reserves estimates
and the third-party audit of our reserves estimates. He has Bachelor of Science and Master of Science degrees in Petroleum
Engineering and over 37 years of industry experience with positions of increasing responsibility in engineering, evaluations,
and business unit management at the Company. The Senior Vice President – Corporate Development reports directly to our
Chief Executive Officer.
Technologies Used in Reserves Estimation The SEC’s reserves rules allow the use of techniques that have been proved
effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable
technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including
computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with
consistency and repeatability in the formation being evaluated or in an analogous formation.
We used a combination of production and pressure performance, wireline wellbore measurements, simulation studies, offset
analogies, seismic data and interpretation, wireline formation tests, geophysical logs and core data to calculate our reserves
estimates, including the material additions to the 2017 reserves estimates.
Based on reasonable certainty of reservoir continuity in US onshore formations where we operate, we may record proved
reserves associated with wells more than one offset location away from an existing proved producing well. All of our wells
drilled that were more than one offset away from a proved producing well at the time of drilling were determined to be
economically producible.
17
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Index to Financial Statements
Third-Party Reserves Audit In each of the years 2017, 2016, and 2015, we retained NSAI to perform audits of proved
reserves. The reserves audit for 2017 included a detailed review of six of our major US onshore and international fields, which
covered approximately 92% of US proved reserves and 99% of international proved reserves (95% of total proved reserves).
The reserves audit for 2016 included a detailed review of nine of our major US onshore and international fields, which covered
approximately 88% of US proved reserves and 99.9% of international proved reserves (92% of total proved reserves). The
reserves audit for 2015 included a detailed review of nine of our major fields and covered approximately 91% of total proved
reserves.
In connection with the 2017 reserves audit, NSAI prepared its own estimates of our proved reserves. In order to prepare its
estimates of proved reserves, NSAI examined our estimates with respect to reserves quantities, future production rates, future
net revenue, and the present value of such future net revenue. NSAI also examined our estimates with respect to reserves
categorization, using the definitions for proved reserves set forth in Rule 4-10(a) of Regulation S-X and subsequent SEC staff
interpretations and guidance.
In the conduct of the reserves audit, NSAI did not independently verify the accuracy and completeness of information and data
furnished by us with respect to ownership interests, crude oil and natural gas production, well test data, historical costs of
operation and development, product prices, or any agreements relating to current and future operations of the fields and sales of
production. However, if in the course of the examination something came to the attention of NSAI which brought into question
the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until it had
satisfactorily resolved its questions relating thereto or had independently verified such information or data.
NSAI determined that our estimates of reserves have been prepared in accordance with the definitions and regulations of the
SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future
years, under existing economic and operating conditions, consistent with the definition in Rule 4-10(a)(24) of Regulation S-X.
NSAI issued an unqualified audit opinion on our proved reserves at December 31, 2017, based upon their evaluation. NSAI
concluded that our estimates of proved reserves were, in the aggregate, reasonable and have been prepared in accordance with
Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of
Petroleum Engineers. NSAI’s report is attached as Exhibit 99.1 to this Annual Report on Form 10-K.
When compared on a field-by-field basis, some of our estimates are greater and some are less than the estimates of NSAI.
Given the inherent uncertainties and judgments that go into estimating proved reserves, differences between internal and
external estimates are to be expected. For proved reserves at December 31, 2017, on a quantity basis, the NSAI field estimates
ranged from 18 MMBoe or 8% below to 9 MMBoe or 2% above as compared with our estimates on a field-by-field basis.
Differences between our estimates and those of NSAI are reviewed for accuracy but are not further analyzed unless the
aggregate variance is greater than 10%. Reserves differences at December 31, 2017 were, in the aggregate, approximately 17
MMBoe, or less than 1%.
Proved Reserves
We have historically added reserves through our exploration program, development activities, and acquisition of producing
properties. Changes in proved reserves were as follows:
Year Ended December 31,
2016
2017
2015
(MMBoe)
Proved Reserves Beginning of Year
Revisions of Previous Estimates
Extensions, Discoveries and Other Additions
Purchase of Minerals in Place
Sale of Minerals in Place
Production
Proved Reserves End of Year
1,437
135
736
57
(261)
(139)
1,965
1,421
64
179
4
(77)
(154)
1,437
1,404
(216)
100
269
(6)
(130)
1,421
Revisions Revisions of previous estimates represent changes in previous reserves estimates, either upward (positive) or
downward (negative), resulting from new information normally obtained from development drilling and production history or
resulting from a change in economic factors, such as commodity prices, operating costs, development costs or abandonment
costs. Revisions primarily included the following:
•
positive price revisions of 30 MMBoe globally, as well as positive performance revisions of 49 MMBoe for the Tamar
field, offshore Israel, 30 MMBoe for the Delaware Basin and 22 MMBoe for the Eagle Ford Shale, partially offset by
abandonment cost increases for US onshore in 2017;
18
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Index to Financial Statements
•
•
positive revisions of 43 MMBoe for the DJ Basin, 42 MMBoe for the Marcellus Shale, 11 MMBoe for the Delaware
Basin, and 10 MMBoe for the Alba field, offshore Equatorial Guinea, due to increased performance and/or lower
development or operating costs; partially offset by negative revisions of 53 MMBoe due to lower commodity prices in
2016; and
negative price revisions of 307 MMBoe, partially offset by positive performance revisions of 81 MMBoe for the
Marcellus Shale and 17 MMBoe for the Delaware Basin in 2015.
Extensions, Discoveries and Other Additions These are additions to proved reserves that result from (1) extension of the
proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (2)
discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields. Extensions, discoveries and
other additions primarily included the following:
•
•
•
increases primarily relate to 99 MMBoe in the DJ Basin and 77 MMBoe in the Delaware Basin as a result of enhanced
completion techniques in our horizontal drilling programs and an increase of 551 MMBoe due to the sanction of the first
phase of development at the Leviathan natural gas field in 2017;
increases of 83 MMBoe in the DJ Basin, 42 MMBoe in the Marcellus Shale, 33 MMBoe in the Delaware Basin and 21
MMBoe in the Eagle Ford Shale, all associated with our horizontal drilling programs in 2016; and
increases of 86 MMBoe in the DJ Basin and 14 MMBoe in the Marcellus Shale associated with our horizontal drilling
programs in 2015.
Approximately 70% of our 2018 capital program is allocated to US onshore, primarily the DJ Basin, Delaware Basin and Eagle
Ford Shale, and more than 25% is allocated to offshore Israel. In turn, we expect that future reserves additions will primarily
come from our development projects in the US onshore and offshore Israel. Potential new discoveries resulting from our
exploration programs in our operational areas as well as global new ventures programs could also lead to future reserve
additions. In addition, we may also purchase proved properties in strategic acquisitions. See Item 7. Management's Discussion
and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Acquisition, Capital
Expenditures and Other Exploration Expenditures.
Purchase of Minerals in Place We occasionally enhance our asset portfolio with strategic acquisitions of producing
properties. Purchases primarily included the following:
•
•
an increase of 57 MMBoe in the Delaware Basin primarily as a result of the Clayton Williams Energy Acquisition in
2017; and
the acquisition of additional acreage, primarily in the Eagle Ford Shale and Delaware Basin in Texas in 2015 in
connection with the Rosetta Merger.
Sale of Minerals in Place We maintain an ongoing portfolio management program through which we may periodically divest
assets. Sales primarily included the following:
•
•
•
a reduction of 241 MMBoe related to the Marcellus Shale upstream divestiture, as well as 20 MMBoe associated with
divestment of non-strategic US onshore assets in 2017;
a reduction of 36 MMBoe in Israel driven by our 3.5% sale of Tamar working interest, as well as a 29 MMBoe
divestment in the Marcellus Shale in 2016; and
the sale of non-strategic US onshore assets in 2015.
See Items 1. and 2. Business and Properties and Item 8. Financial Statements and Supplementary Data – Note 4. Acquisitions,
Divestitures and Merger.
Production See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of
Operations - E&P - Revenues and Critical Accounting Policies and Estimates – Reserves and Item 8. Financial Statements and
Supplementary Data – Supplemental Oil and Gas Information (Unaudited).
19
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Index to Financial Statements
Proved Undeveloped Reserves (PUDs) As of December 31, 2017, our PUDs totaled 249 MMBbls of crude oil and
condensate, 4.5 Tcf of natural gas, and 99 MMBbls of NGLs for a total of 1,097 MMBoe, or 56% of proved reserves. Changes
in PUDs that occurred during the year are summarized below:
(MMBoe)
Proved Undeveloped Reserves Beginning of Year
Revisions of Previous Estimates
Extensions, Discoveries and Other Additions
Purchase of Minerals in Place
Sale of Minerals in Place
Conversion to Proved Developed
Proved Undeveloped Reserves End of Year
United
States
Israel
Total
422
26
174
36
(54)
(122)
482
64
—
551
—
—
—
615
486
26
725
36
(54)
(122)
1,097
Revisions of previous estimates include the transfer of PUDs to unproved reserve categories as a result of changes in
development plans and/or the impact of changes in commodity prices, and the addition of new PUDs arising from current
development plans. Positive revisions of 26 MMBoe in the US for 2017 included 7 MMBoe related to positive price revisions
and 19 MMBoe related to enhancements of our horizontal drilling programs.
Extensions, discoveries and other additions include the addition of proved reserves through additional drilling or the discovery
of new reservoirs in proven fields. During 2017, we recorded the following additions as a result of successful expansion of our
long lateral well programs in US onshore and recording of reserves for Leviathan:
•
•
•
•
94 MMBoe in the DJ Basin;
74 MMBoe in the Delaware Basin;
6 MMBoe in the Eagle Ford Shale; and
551 MMBoe in the Leviathan field.
Conversion to proved developed reserves included the following transfers:
•
•
•
•
34 MMBoe in the DJ Basin;
17 MMBoe in the Delaware Basin;
60 MMBoe in the Eagle Ford Shale; and
11 MMBoe in the Marcellus Shale, prior to divestiture.
US PUDs Locations In 2017, we converted 122 MMBoe of our US PUDs, or 29% of our US PUDs beginning balance, to
developed status. Based on our current inventory of identified horizontal well locations and our anticipated rate of drilling and
completion activity, we expect our US PUDs recorded as of December 31, 2017 to be converted to proved developed reserves
within five years of initial disclosure.
As of December 31, 2017, our US PUDs included:
•
•
•
263 MMBoe in the DJ Basin;
181 MMBoe in the Delaware Basin; and
38 MMBoe in the Eagle Ford Shale.
Our PUDs are expected to be recovered from new wells on undrilled acreage or from existing wells where additional capital
expenditures are required for completion, such as drilled but uncompleted (DUC) wells. As of December 31, 2017, we had
approximately 32 MMBoe of PUDs associated with DUC well locations related to our US onshore operations, approximately
75% of which are in the DJ Basin and the remainder are in the Delaware Basin and Eagle Ford Shale.
International PUDs Locations As of December 31, 2017, our international PUDs included 615 MMBoe in Israel, of which 551
MMBoe relate to the Leviathan field, which is currently in the first phase of development. The Tamar field contains 35
MMBoe, and the Tamar Southwest field, which is awaiting government approval of the development plan, contains 29
MMBoe. Our Tamar Southwest PUDs of 29 MMBoe, or less than 5% of our international PUDs, are expected to remain
undeveloped for five years or longer since initial disclosure in 2013. We have been working with the government of Israel for
the approval of the development plan and have continued capital investment within this field, including laying subsea
equipment in 2017 for future tie-in of field production into existing Tamar infrastructure. Other than the Tamar Southwest
PUDs, we expect all of our international PUDs, including those associated with the initial phase of development at the
Leviathan field, to be converted to proved developed reserves within five years of initial disclosure.
20
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Index to Financial Statements
Development Costs Costs incurred to convert PUDs to proved developed reserves were approximately $1.2 billion in 2017,
$656 million in 2016, and $1.5 billion in 2015. Costs incurred in 2017 primarily related to the DJ Basin, Delaware Basin and
Eagle Ford Shale development projects, as well as certain costs incurred for the development of the Tamar 8 well. In addition,
we incurred approximately $416 million in 2017 to advance the development of the Leviathan PUDs which are expected to be
converted to proved developed reserves in 2019.
Estimated future development costs relating to the development of all PUDs are projected to be approximately $1.7 billion in
2018, $1.9 billion in 2019, and $1.4 billion in 2020. Estimated future development costs include capital spending on
development projects and PUDs related to development projects will be reclassified to proved developed reserves when
production commences.
Drilling Plans Our long range development plans will result in the conversion of all PUDs to developed reserves within five
years of their initial disclosure, with the exception of the previously mentioned Tamar Southwest PUDs. PUDs associated with
the Tamar Southwest field are expected to be converted to proved developed reserves prior to the end of 2020 as contemplated
in our long range development plans, subject to local government approval. Initial production from all PUDs is expected to
begin during the years 2018 to 2022.
In accordance with US GAAP, we disclose a standardized measure of discounted future net cash flows related to our proved
reserves. In order to standardize the measure, all companies are required to use a 10% discount rate and SEC pricing rules. This
prescribed calculation can result in some PUDs having negative present worth, meaning while these PUDs have positive cash
flows, the rate of return is lower than 10%. As of December 31, 2017, we had no PUDs with a negative present worth when
discounted at 10%.
We consider the economic development of reserves based on our estimates of future pricing, future investments, production and
other economic factors that are excluded from the SEC reserves requirements and are committed to developing PUDs within
five years of initial disclosure. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of
Operations – Operating Outlook – 2018 Capital Investment Program.
For more information see the following:
•
•
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting
Policies and Estimates – Reserves for further discussion of our reserves estimation process; and
Item 8. Financial Statements and Supplementary Data – Supplemental Oil and Gas Information (Unaudited) for
additional information regarding estimates of crude oil, NGL and natural gas reserves, including estimates of proved,
proved developed, and proved undeveloped reserves, the standardized measure of discounted future net cash flows, and
the changes in the standardized measure of discounted future net cash flows.
21
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Index to Financial Statements
Sales Volumes, Price and Cost Data Sales volumes, price and cost data are as follows:
Sales Volumes
Average Sales Price
Crude Oil &
Condensate
MBbl
NGLs
MBbl
Natural
Gas
MMcf
Crude Oil &
Condensate
Per Bbl
NGLs Per
Bbl
Natural
Gas
Per Mcf
Production
Cost (1)
Per BOE
Year Ended December 31, 2017 (2)
United States
DJ Basin
Marcellus Shale
Other US
Total US
Israel
Tamar Field
Other Israel
Total Israel
Equatorial Guinea (3)
Total Consolidated Operations
Equity Investee (4)
Total
Year Ended December 31, 2016 (2)
United States
DJ Basin
Marcellus Shale
Other US
Total US
Israel
Tamar Field
Other Israel
Total Israel
Equatorial Guinea (3)
Total Consolidated Operations
Equity Investee (4)
Total
Year Ended December 31, 2015 (2)
United States
DJ Basin
Marcellus Shale
Other US
Total US
Israel
Tamar Field
Other Israel
Total Israel
Equatorial Guinea (3)
United Kingdom
Total Consolidated Operations
Equity Investee (4)
Total
21,564
233
18,757
40,554
130
—
130
6,460
47,144
662
47,806
20,342
431
15,572
36,345
140
—
140
9,415
45,900
629
46,529
20,909
673
7,680
29,262
121
—
121
11,416
88
40,887
554
41,441
6,911
1,654
12,521
21,086
—
—
—
—
21,086
2,162
23,248
7,651
3,094
9,087
19,832
—
—
—
—
19,832
1,993
21,825
6,910
3,480
3,705
14,095
—
—
—
—
—
14,095
1,850
15,945
70,660
63,443
87,364
221,467
96,894
2,346
99,240
87,269
407,976
—
407,976
82,431
177,872
62,017
322,320
102,280
528
102,808
85,987
511,115
—
511,115
85,369
143,465
29,806
258,640
91,884
136
92,020
82,729
49
433,438
—
433,438
$
$
$
$
$
$
50.20
36.91
48.01
49.11
46.95
—
46.95
53.68
49.73
55.13
49.84
40.85
28.25
38.26
39.59
36.67
—
36.67
43.54
40.39
45.44
40.46
44.37
22.39
42.83
43.46
46.91
—
46.91
48.85
55.52
45.00
48.85
45.05
$
$
$
$
$
$
25.22
23.81
22.34
23.40
—
—
—
—
23.40
38.48
24.81
14.66
16.34
14.65
14.92
—
—
—
—
14.92
26.30
15.96
14.21
14.04
13.25
13.91
—
—
—
—
—
13.91
28.40
15.59
$
$
$
$
$
$
$
$
$
$
$
$
2.96
3.15
2.99
3.02
5.37
3.56
5.32
0.27
3.01
—
3.01
2.80
1.68
2.42
2.11
5.22
3.20
5.21
0.27
2.42
—
2.42
2.53
1.75
2.56
2.10
5.34
3.01
5.34
0.27
6.32
2.44
—
2.44
4.46
1.05
6.48
4.81
2.02
N/M
2.01
4.30
4.31
N/M
N/M
3.99
0.90
6.65
3.74
2.58
N/M
2.60
4.40
3.72
N/M
N/M
5.75
1.38
7.15
4.46
3.12
N/M
3.15
5.22
N/M
4.54
N/M
N/M
N/M Amount is not meaningful.
(1) Average production cost includes crude oil and natural gas operating costs and workover and repair expense and excludes production and
ad valorem taxes and transportation expense.
22
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Index to Financial Statements
(2) For each respective year, reserves associated with the Delaware Basin or the Eagle Ford Shale did not comprise 15% or more of total
reserves on a BOE basis.
(3) Natural gas from the Alba field is 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.
(4) Volumes represent sales of condensate and LPG from the LPG plant in Equatorial Guinea.
Revenues from sales of crude oil, NGLs and natural gas have accounted for 90% or more of consolidated revenues for each of
the last three fiscal years.
At December 31, 2017, our operated properties accounted for substantially all of our total production. Being the operator of a
property improves our ability to directly influence production levels and the timing of projects, while also enhancing our
control over operating expenses and capital expenditures.
Productive Wells The number of productive crude oil and natural gas wells in which we held an interest at December 31, 2017
was as follows:
United States
Israel
Equatorial Guinea
Total
Crude Oil Wells
Net
Gross
Natural Gas Wells
Net
Gross
Total
Gross
Net
3,565
—
5
3,570
2,682
—
2
2,684
4,918
7
23
4,948
4,382
2
8
4,392
8,483
7
28
8,518
7,064
2
10
7,076
Productive wells are producing wells and wells mechanically capable of production. A gross well is a well in which a working
interest is owned. The number of gross wells is the total number of wells in which a working interest is owned. The number of
net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof.
Wells with multiple completions are counted as one well in the table above.
Developed and Undeveloped Acreage Developed and undeveloped acreage (including both leases and concessions) in which
we held an interest at December 31, 2017 was as follows:
(thousands of acres)
United States
Onshore
Gulf of Mexico
Total United States
International
Israel
Equatorial Guinea (1)
Suriname
Newfoundland, Canada
Gabon
Cyprus
Cameroon
Other International
Total International
Total
Developed Acreage
Net
Gross
Undeveloped Acreage
Gross
Net
754
93
847
185
284
—
—
—
—
—
2
471
1,318
504
52
556
78
118
—
—
—
—
—
—
196
752
564
247
811
284
81
2,095
2,331
671
95
168
284
6,009
6,820
358
171
529
116
30
419
681
403
33
168
211
2,061
2,590
(1) Undeveloped acreage includes an exploration lease totaling approximately 55,000 gross (19,000 net) acres which had
expired in 2016. The lease was subsequently negotiated with the government of Equatorial Guinea in 2017 and was
extended.
Developed acreage is comprised of leased acres that are within an area spaced by or assignable to a productive well.
Undeveloped acreage is comprised of leased acres with defined remaining terms and not within an area spaced by or assignable
to a productive well. A gross acre is any leased acre in which a working interest is owned. A net acre is comprised of the total of
the owned working interest(s) in a gross acre expressed in a fractional format.
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The above table includes certain undeveloped acreage that is set to expire if production is not established or we take no other
action to extend the terms of the leases, licenses, or concessions within a specified period of time. Approximately 0.9 million
(including 0.4 million in Suriname and 0.4 million in Gabon), 0.3 million, and 0.1 million net acres will expire in 2018, 2019,
and 2020, respectively.
Drilling Activity The results of crude oil and natural gas wells drilled and completed for each of the last three years were as
follows:
Net Exploratory Wells
Dry
Total
Productive
Net Development Wells
Dry
Total
Productive
Year Ended December 31, 2017
United States
Israel
Suriname
Total
Year Ended December 31, 2016
United States
Total
Year Ended December 31, 2015
United States
Equatorial Guinea
Cameroon
Other International
Total
—
—
—
—
0.4
0.4
1.5
—
—
—
1.5
—
—
0.2
0.2
0.5
0.5
4.0
—
0.5
0.4
4.9
—
—
0.2
0.2
0.9
0.9
5.5
—
0.5
0.4
6.4
185.3
0.3
—
185.6
156.7
156.7
212.5
0.3
—
—
212.8
—
—
—
—
—
—
—
—
—
—
—
185.3
0.3
—
185.6
156.7
156.7
212.5
0.3
—
—
212.8
Total
185.3
0.3
0.2
185.8
157.6
157.6
218.0
0.3
0.5
0.4
219.2
In addition to the wells drilled and completed in 2017 included in the table above, wells that were in the process of drilling or
completing at December 31, 2017 were as follows:
United States
Israel
Equatorial Guinea
Cameroon
Cyprus
Total
Exploratory(1)
Development(2)
Total
Gross
Net
Gross
Net
Gross
Net
1
1
2
1
1
6
0.5
0.3
0.9
1.0
0.4
3.1
114
5
—
—
—
119
105.0
2.0
—
—
—
107.0
115
6
2
1
1
125
105.5
2.3
0.9
1.0
0.4
110.1
(1)
(2)
Includes exploratory wells drilled and suspended awaiting a sanctioned development plan or being evaluated to assess the economic
viability of the well.
Includes wells pending completion activities. Israel development wells include the Leviathan 3, 4, 5 and 7 development wells and the
Tamar Southwest well.
See Item 8. Financial Statements and Supplementary Data – Note 6. Capitalized Exploratory Well Costs and Undeveloped
Leasehold Costs for additional information on suspended exploratory wells.
Domestic Marketing Activities Crude oil, natural gas, condensate and NGLs produced in the US onshore and Gulf of Mexico
are sold under short-term and long-term contracts at market-based prices adjusted for location and quality. Onshore production of
crude oil and condensate is distributed through pipelines and by trucks and rail cars to gatherers, transportation companies and
refineries. Gulf of Mexico production is distributed through pipelines.
With the advent of US onshore shale gas, demand has increased for access to takeaway pipelines for ballooning production
volumes. For example, in the Permian Basin, midstream suppliers are working to construct new gathering, transportation and
processing facilities or to repurpose existing infrastructure in an effort to proactively outpace anticipated production growth as
well as expected future LNG demand from export facilities on the Gulf Coast.
International Marketing Activities Our share of crude oil and condensate from the Aseng and Alen fields is sold at market-
based prices to Glencore Energy UK Ltd (Glencore Energy). Our share of crude oil and condensate from the Alba field is sold
to Glencore Energy under a short-term sales contract, subject to renewal. These products are transported by tanker.
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Natural gas from the Alba field is sold for $0.25 per MMBtu to a methanol plant, an LPG plant, an unaffiliated LNG plant and
a power generation plant. The sales contract with the methanol plant runs through 2026, and the sales contract with the LNG
plant runs through 2023. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method.
In Israel, we sell natural gas from the Tamar field, and have agreements with multiple customers to sell natural gas under long-
term contracts, with initial terms ranging from 15 to 17 years. See Delivery and Firm Transportation Commitments, below.
Delivery and Firm Transportation Commitments
Domestic Contracts We have entered into various long-term gathering, processing and transportation contracts for some of our
US onshore production, with remaining terms of one to 11 years. We use long-term contracts such as these to provide
production flow assurance and ensure access to markets for our products at the best possible price and at the lowest possible
logistics cost.
Certain of these contracts require us to make payments for any shortfalls in delivering or transporting minimum volumes under
the commitments. As properties are undergoing development activities, we may experience temporary shortfalls until
production volumes increase to meet or exceed the minimum volume commitments.
For 2017, 2016, and 2015, we incurred expense of approximately $47 million, $58 million, and $33 million, respectively,
related to volume deficiencies and/or unutilized commitments primarily in our US onshore operations. These amounts are
recorded as marketing expense in our consolidated statements of operations.
We expect to continue to incur expense related to deficiency and/or unutilized commitments in the near-term. Should
commodity prices decline or if we are unable to continue to develop our properties as planned, or certain wells become
uneconomic and are shut-in, we could incur additional shortfalls in delivering or transporting the minimum volumes and we
could be required to make payments in the event that these commitments are not otherwise offset. We continually seek to
optimize under-utilized assets through capacity release and third-party arrangements, as well as, for example, through the
shifting of transportation of production from rail cars to pipelines when we receive a higher netback price. We may continue to
experience these shortfalls both in the near and long-term.
Our financial commitments under these contracts are included in our contractual obligations disclosures. In addition, we have
retained certain other firm transportation agreements after the completing the Marcellus Shale upstream divestiture. See Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources –
Contractual Obligations.
Israel Natural Gas Sales and Purchase Agreements We currently sell natural gas from our Tamar field, offshore Israel, to the
IEC and numerous other Israeli purchasers, including independent power producers, cogeneration facilities and industrial
companies. Most contracts provide for the sale of natural gas over an initial term of 15 to 17 years. Some of the contracts
provide for an increase or reduction in total quantities, and some contracts are interruptible during certain contract periods.
Sales prices may be based on an initial base price subject to price indexation over the life of the contract and have a contractual
floor. The IEC contract provides for price reopeners in certain years with limits on the increase/decrease from the contractual
price.
Under the contracts, we and our partners have a financial exposure in the event we cannot fully deliver the contract quantities.
This exposure is capped by contract and will be reflected as a reduction in sales price to the purchaser for periods in which we
are delivering partial contract quantities, or as a direct payment to the customer under certain circumstances and with a cap. The
cap is subject to force majeure considerations. We believe that any such sales price adjustments or direct payments would not
have a material impact on our earnings or cash flows.
As of December 31, 2017, a total of approximately 5.4 Tcf, gross (1.7 Tcf, net), of natural gas remained to be delivered under
our Tamar contracts. As of December 31, 2017, we have recorded 2.0 Tcf, net, of proved natural gas reserves, including proved
developed reserves of 1.8 Tcf, net, and PUD reserves of 212 Bcf, net, for the Tamar field. Based on current production levels
and future development plans, our available quantities of proved reserves are more than sufficient to meet near-term delivery
commitments associated with Tamar sale agreements without further capital investment.
We are also actively engaged in domestic and regional marketing activities for future sales of the natural gas reserves recorded
for the Leviathan field. See Eastern Mediterranean (Israel and Cyprus), above.
Significant Purchasers BP North American Funding (BP) and Shell Trading (US) (Shell) were the largest single purchasers
of our 2017 production. Sales to BP accounted for 10% of 2017 total crude oil, natural gas and NGL sales, or 15% of 2017
crude oil sales. Sales to Shell accounted for 13% of our 2017 total crude oil, natural gas and NGL sales, or 22% of crude oil
sales. Both BP and Shell purchased crude oil and condensate domestically from our US onshore operations and Gulf of Mexico
operations.
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No other single purchaser accounted for 10% or more of crude oil, natural gas and NGL sales in 2017. We maintain credit
insurance associated with specific purchasers and believe that the loss of any one purchaser would not have a material effect on
our financial position or results of operations since there are numerous potential purchasers of our production.
Hedging Activities Commodity prices continue to be volatile and are affected by a variety of factors beyond our control. We
use derivative instruments to reduce the impact of commodity price uncertainty and increase cash flow predictability relating to
the marketing of our crude oil and natural gas. As a result of hedging, a portion of near-term cash flow volatility is reduced.
We exercise strong management of our hedging program with strong oversight by our Board of Directors. For additional
information, see Item 1A. Risk Factors, Item 7A. Quantitative and Qualitative Disclosures About Market Risk, and Item 8.
Financial Statements and Supplementary Data – Note 8. Derivative Instruments and Hedging Activities.
Regulations
Exploration for, and production and marketing of, crude oil, natural gas and NGLs are extensively regulated at the federal,
state, and local levels in the US, and internationally. Crude oil, natural gas and NGL development and production activities are
subject to various laws and regulations (and orders of regulatory bodies pursuant thereto) governing a wide variety of matters,
including, among others, allowable rates of production, transportation, prevention of waste and pollution, and protection of the
environment. Laws affecting the crude oil and natural gas industry are under constant review for amendment or expansion over
time and frequently impose more stringent requirements on crude oil and natural gas companies.
Our ability to economically produce and sell crude oil, natural gas and NGLs is affected by a number of legal and regulatory
factors, including federal, state and local laws and regulations in the US and laws and regulations of foreign nations. Many of
these governmental bodies have issued rules, regulations and orders that require extensive efforts to ensure compliance, that
impose incremental costs to comply, and that carry substantial penalties for failure to comply. These laws, regulations and
orders may restrict the rate of crude oil, natural gas and NGL production below the rate that would otherwise exist in the
absence of such laws, regulations and orders. The regulatory requirements on the crude oil and natural gas industry often result
in incremental costs of doing business and consequently affect our profitability. See Item 1A. Risk Factors – We are subject to
increasing governmental regulations and environmental requirements that may cause us to incur substantial incremental costs.
Internationally, our operations are subject to legal and regulatory oversight by energy-related ministries or other agencies of our
host countries, each having certain relevant energy or hydrocarbons laws. Examples include:
•
•
•
•
the Ministry of Mines and Hydrocarbons, which, under such laws as the hydrocarbons law enacted in 2006 by the
government of Equatorial Guinea, regulates our exploration, development and production activities offshore Equatorial
Guinea;
the Ministry of Energy, which regulates our exploration and development activities offshore Israel and the Israeli
electricity market into which we sell our natural gas production;
the Israeli Antitrust Commission, which reviews Israel's domestic natural gas sales and ownership in offshore blocks and
leases; and
the Ministry of Energy, Commerce, Industry and Tourism, which regulates our exploration and development activities
offshore Cyprus.
Examples of US federal agencies with regulatory authority over our exploration for, and production and sale of, crude oil,
natural gas and NGLs include:
•
•
•
•
•
•
the Bureau of Land Management (BLM), the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety
and Environmental Enforcement (BSEE), which under laws such as the Federal Land Policy and Management Act,
Endangered Species Act, National Environmental Policy Act and Outer Continental Shelf Lands Act, have certain
authority over our operations on federal lands and waters, particularly in the Rocky Mountains and Gulf of Mexico;
the Office of Natural Resources Revenue, which under the Federal Oil and Gas Royalty Management Act of 1982, has
certain authority over our payment of royalties, rentals, bonuses, fines, penalties, assessments, and other revenue;
the US Environmental Protection Agency (EPA) and the Occupational Safety and Health Administration (OSHA), which
under laws such as the Comprehensive Environmental Response, Compensation and Liability Act, the Resource
Conservation and Recovery Act, the Oil Pollution Act of 1990, the Clean Air Act, the Clean Water Act, the Safe Drinking
Water Act, and the Occupational Safety and Health Act have certain authority over environmental, health and safety
matters affecting our operations;
the US Fish and Wildlife Service (FWS) and US National Marine Fisheries Service, which under the Endangered Species
Act have authority over activities that may result in the take of any endangered or threatened species or its habitat;
the US Army Corps of Engineers, which under the Clean Water Act has authority to regulate the construction of
structures involving the fill of certain waters and wetlands subject to federal jurisdiction, including well pads, pipelines
and roads;
the Federal Energy Regulatory Commission (FERC), which under laws such as the Energy Policy Act of 2005 has certain
authority over the marketing and transportation of crude oil, natural gas and NGLs we produce onshore and from the
Gulf of Mexico; and
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•
the Department of Transportation, which has certain authority over the transportation of products, equipment and
personnel necessary to our US onshore and Gulf of Mexico operations.
Other US federal agencies with certain authority over our business include the Internal Revenue Service (IRS) and the SEC. In
addition, we are governed by the rules and regulations of the NYSE, upon which shares of our common stock are traded.
Among the laws affecting our operations are the following:
Environmental Matters We take into account the cost of complying with environmental regulations in planning, designing,
drilling, operating, and abandoning wells. In most instances, the regulatory requirements relate to the handling and disposal of
drilling and production wastes, water and air pollution control procedures, facility siting and construction, prevention of and
responses to leaks and spills, and the remediation of petroleum-product contamination. These laws and regulations may require
the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances
that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or
drilling activities on certain lands lying within wilderness, wetlands, ecologically or seismically sensitive areas, and other
protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned
wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that
additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations.
Under state and federal laws, we could be required to remove or remediate previously disposed wastes, including wastes
disposed of or released by us, or by prior owners or operators, in accordance with current laws, to suspend or cease operations
in contaminated areas, or to perform remedial well plugging operations or cleanups. The EPA and various state agencies have
limited the disposal options for hazardous and non-hazardous wastes and may continue to do so. The owner and operator of a
site, and persons that treated, disposed of, or arranged for the disposal of hazardous substances found at a site, may be liable,
without regard to fault or the legality of the original conduct, for the release of a hazardous substance into the environment. The
EPA, state environmental agencies and, in some cases, third parties are authorized to take actions in response to threats to
human health or the environment and to seek to recover from responsible classes of persons the costs of such action. Moreover,
it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage
allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.
Furthermore, certain wastes generated by our crude oil and natural gas operations that are currently exempt from the definition
of hazardous waste may in the future be subject to considerably more rigorous and costly operating and disposal requirements.
Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration,
development and production wastes as “hazardous wastes.” Also, in December 2016, the EPA agreed in a consent decree to
review its regulation of oil and gas waste. It has until March 2019 to determine whether any revisions are necessary.
Under federal and state occupational safety and health laws, we must develop and maintain information about hazardous
materials used, released, or produced in our operations. Certain portions of this information must be provided to employees,
state and local governmental authorities, and local citizens. We are also subject to the requirements and reporting set forth in
federal workplace standards.
Moreover, certain state or local laws or regulations and common law may impose liabilities in addition to, or restrictions
more stringent than, those described herein.
We have made and will continue to make expenditures necessary to comply with environmental requirements. We do not
believe that compliance with such requirements will have a material adverse effect on our capital expenditures, earnings or
competitive position. Although such requirements do have a substantial impact on the crude oil and natural gas industry,
they do not appear to affect us to any greater or lesser extent than other companies in the industry.
The following is a summary of the more significant US environmental developments and requirements that may affect our
operations.
Various state and federal statutes such as the Endangered Species Act (ESA) prohibit certain actions that adversely affect
endangered or threatened species and their habitat, wetlands, migratory birds, marine mammals, or natural resources. Where
the taking or harm of such species occurs or may occur, or where damages to wetlands or natural resources may occur, the
government or private parties may act to prevent crude oil and natural gas exploration activities. In particular, a federal or
state agency could order a complete halt to drilling activities in certain locations or during certain seasons when such
activities could result in a serious adverse effect upon a protected species. The presence of a protected species in areas
where we operate could adversely affect future production from those areas and government agencies frequently add to the
lists of protected species. For example, listing of the Lesser Prairie Chicken likewise could impact our operations in the
Delaware Basin. The Lesser Prairie Chicken was removed from the ESA list of endangered species in July 2016 after a
federal court invalidated the FWS’s listing of the bird as threatened because the FWS failed to give proper consideration to
voluntary conservation measures; however, the FWS announced in November 2016 an ongoing new status review of the
Lesser Prairie Chicken to determine whether listing is still warranted.
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The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act” or “CWA,” the Safe
Drinking Water Act, the Oil Pollution Act and analogous state laws and regulations promulgated thereunder impose
restrictions and strict controls regarding the discharge of pollutants, including produced waters and other gas and oil wastes,
into navigable waters. Provisions of the CWA require authorization from the US Army Corps of Engineers, or the “Corps”,
prior to the placement of dredge or fill material into jurisdictional waters. Spill prevention, control and countermeasure plan
requirements under federal law require appropriate containment berms and similar structures to help prevent the
contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak.
On June 29, 2015, the EPA and Corps jointly published the final rule defining the scope of the EPA’s and Corps’
jurisdiction, known as the “Clean Water Rule.” The Clean Water Rule has been challenged in multiple federal courts;
however, at this time, we cannot predict the outcome of this litigation. Subsequently, the EPA and the Corps proposed a
rulemaking in June 2017 to repeal the June 2015 rule, and also announced their intent to issue a new rule defining the Clean
Water Act’s jurisdiction. Both agencies also published a proposed rule in November 2017 delaying implementation of the
Clean Water Rule for two years. As a result, future implementation of the June 2015 rule is uncertain at this time. To the
extent the rule expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to spill
prevention, storm water management, and wetlands permitting. We are continuing to monitor the regulatory updates and to
evaluate the impact of the new rule on our operations.
Also, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional
oil and natural gas extraction facilities to publicly owned wastewater treatment plants. The EPA is also conducting a study
of private wastewater treatment facilities (also known as centralized waste treatment, or CWT, facilities) accepting oil and
natural gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities
accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial
characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities. In addition, the EPA
previously announced its plans to develop a Notice of Proposed Rulemaking by June 2018, which would describe a
proposed mechanism - regulatory, voluntary, or a combination of both - to collect data on hydraulic fracturing chemical
substances and mixtures.
The federal Clean Air Act, as amended, and comparable state laws and regulations, regulate emissions of various air
pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues
to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required
to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur
capital costs in order to remain in compliance. These laws and regulations may increase the costs of compliance for some
facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal
penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws
and regulations.
There also have been a series of recent air regulations and proposals that affect, or that may affect, our operations. In 2012,
for example, the EPA issued New Source Performance Standards (NSPS) and National Emission Standards for Hazardous
Air Pollutants to control air emissions associated with crude oil, natural gas and NGL production, including natural gas
wells that are hydraulically fractured. In addition to addressing emissions from storage tanks and other equipment, those
regulations required technologies and processes that, while reducing emissions, enable companies to collect additional
natural gas that can be sold. Specifically, as of January 2015, owners and operators of natural gas wells must use emissions
reduction technology called “green completions,” technologies that were already widely deployed at wells. The EPA
received numerous requests for reconsideration of these rules from both industry and the environmental community, and
court challenges to the rules were also filed. In response, the EPA has issued, and will likely continue to issue, revised rules
responsive to some of the requests for reconsideration. In particular, on May 12, 2016, the EPA amended its regulations to
impose new standards for methane and volatile organic compounds emissions for certain new, modified, and reconstructed
equipment, processes, and activities across the oil and natural gas sector. However, in a March 28, 2017 executive order, the
EPA was directed to review the 2016 regulations and, if appropriate, to initiate a rulemaking to rescind or revise them
consistent with the stated policy of promoting clean and safe development of the nation’s energy resources, while at the
same time avoiding regulatory burdens that unnecessarily encumber energy production. On June 16, 2017, the EPA
published a proposed rule to stay for two years certain requirements of the 2016 regulations, including fugitive emission
requirements. These standards, as well as any future laws and their implementing regulations, may require us to obtain pre-
approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air
emissions, impose stringent air permit requirements, or mandate the use of specific equipment or technologies to control
emissions. To date, these rules have had minimal impact on our business since the reduction of greenhouse gas (GHG)
emissions already was one of our priorities and we had been working to improve our methods to reduce GHGs through
operational and business practices. For example, we have undertaken emission reduction projects such as our US Vapor
Recovery Unit (VRU) program, where we have installed VRUs to capture natural gas that would otherwise be flared on a
substantial number of our tank batteries.
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Also, on May 12, 2016, the EPA issued a final rule regarding the criteria for aggregating multiple small surface sites into a
single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities,
on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and
requirements, which could increase our compliance costs and may require facility siting and design changes.
As another prong of the previous US Administration's methane strategy, on November 15, 2016, the BLM finalized a rule to
reduce the flaring, venting and leaking of methane from oil and gas operations on federal and Indian lands. The rule
requires operators to use currently available technologies and equipment to reduce flaring, periodically inspect their
operations for leaks, and replace outdated equipment that vents large quantities of gas into the air. The rule also clarifies
when operators owe the government royalties for flared gas. State and industry groups have challenged this rule in federal
court, asserting that the BLM lacks authority to prescribe air quality regulations. On March 28, 2017, the BLM was
directed by executive order to review the above rule and, if appropriate, to initiate a rulemaking to rescind or revise it.
Accordingly, on December 8, 2017, the BLM published a final rule to suspend or delay certain requirements of the 2016
methane rule until January 17, 2019. Further legal challenges are expected. At this time, it is uncertain when, or if, the
rules will be implemented, and what impact they would have on our operations. It also bears noting that substantially all of
our US onshore properties are subject to EPA’s requirements for reporting annual GHG emissions. Information in such
reports could form the basis of further GHG regulations.
In another air development, the EPA announced in October 2015 that it was lowering the primary national ambient air quality
standard for ozone from 75 parts per billion to 70 parts per billion. Implementation will take place over several years; however,
areas that cannot meet the new standard eventually will need to impose additional requirements on sources of VOCs and other
ozone precursors which could increase the cost of siting and operating our facilities.
Apart from these federal matters, most of the states where we operate have separate authority to regulate operational and
environmental matters.
Colorado In February 2013, the Colorado Oil and Gas Conservation Commission (COGCC) approved setback rules for crude
oil and natural gas wells and production facilities located in close proximity to occupied buildings. Previously, the COGCC
had allowed setback distances of 150 feet in rural areas and 350 feet in high density urban areas. These have been increased to a
uniform 500 feet statewide setback from occupied buildings and 1,000 feet from high occupancy building units. The setback
rules also require operators to utilize increased mitigation measures to limit potential drilling impacts to surface owners and the
owners of occupied building units. In addition, the rules require advance notice to surface owners, the owners of occupied
buildings and local governments prior to the filing of an Application for Permit to Drill or Oil and Gas Location Assessment as
well as outreach and communication efforts by an operator.
The COGCC also has implemented rules making Colorado the first state to require sampling of groundwater for hydrocarbons
and other indicator compounds both before and after drilling. Those statewide rules require sampling of up to four water wells
within a half mile radius of a new crude oil and natural gas well before drilling, between six and 12 months after completion,
and between five and six years after completion. For the Greater Wattenberg Area, the COGCC requires operators to sample
only one water well per quarter governmental section before drilling and between six to 12 months after completion. Further,
the COGCC has adopted rules increasing the maximum penalty for violations of its requirements.
The state environmental agency, the Colorado Department of Public Health and Environment, likewise has adopted measures to
regulate air emissions, water protection, and waste handling and disposal relating to our crude oil and natural gas exploration
and production. For air, the Colorado Department of Public Health and Environment has extended the EPA’s emissions
standards for crude oil and natural gas operations to directly control methane. The final rules, which cover the life cycle of oil
and gas development, production, and maintenance, reflect a collaborative effort by the Environmental Defense Fund, Noble
Energy and other oil and gas operators.
Some of the counties and municipalities where we operate in Colorado have adopted their own regulations or ordinances that
impose additional restrictions on our crude oil and natural gas exploration and production. To date these have not significantly
impacted our operations. However, a few localities in Colorado have tried to prohibit certain exploration and production
activities, particularly use of hydraulic fracturing within their boundaries. In May 2016, the Colorado Supreme Court found that
the local laws intended to increase regulatory requirements on oil and gas development were preempted by existing state law
and were therefore invalid. See Hydraulic Fracturing, below.
In April 2015, we entered into a joint consent decree (Consent Decree) with the EPA, US Department of Justice, and State of
Colorado to improve emission control systems at a number of our condensate storage tanks that are part of our upstream oil and
natural gas operations within the Non-Attainment Area of the DJ Basin. The Consent Decree was entered by the US District
Court of Colorado on June 2, 2015 and requires us to perform certain activities. All fines required under the Consent Decree
were paid in 2015; however, the required injunctive relief remains ongoing. Based on currently available information, we have
concluded that the remaining obligations will not have a material adverse effect on our financial position, results of operations
or cash flows. See Item 1A. Risk Factors – Our operations require us to comply with a number of US and international laws
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and regulations, violations of which could result in substantial fines or sanctions and/or impair our ability to do business and
Item 8. Financial Statements and Supplementary Data – Note 17. Commitments and Contingencies.
Texas Texas has regulations governing conservation matters, including provisions for the unitization or pooling of oil and gas
properties, the establishment of maximum rates of production from oil and gas wells, the regulation of spacing, and
requirements for plugging and abandonment of wells.
In February 2012, the Texas Railroad Commission (RRC) implemented a hydraulic fracturing disclosure rule, requiring Texas
oil and gas operators to disclose on the FracFocus website, chemical ingredients and water volumes used in hydraulic fracturing
treatments.
In May 2013, the RRC issued an updated “well integrity rule” that addresses requirements for drilling, casing and cementing
wells. The rule also includes new testing and reporting requirements, including clarifying that cementing reports must be
submitted after well completion or after cessation of drilling, whichever is earlier.
In October 2014, the RRC adopted new permit rules for injection wells to address seismic activity concerns within the state.
Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit
applications, provide for more frequent monitoring and reporting for certain wells, and allow the RRC to modify, suspend, or
terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. The RRC has
used this authority to deny permits for waste disposal wells.
US Offshore Regulatory Developments Our operations on federal oil and natural gas leases in the Gulf of Mexico are subject
to regulation by BSEE and BOEM. These leases contain relatively standardized terms and require compliance with detailed
BSEE and BOEM regulations and orders issued pursuant to various federal laws, including the Outer Continental Shelf Lands
Act (OCSLA). These laws and regulations are subject to change, and many new requirements, including those related to safety,
permitting and performance, were imposed by BSEE and BOEM subsequent to the April 2010 Deepwater Horizon incident.
In April 2016, the BSEE issued a final rule entitled “Oil and Gas and Sulfur Operations in the Outer Continental Shelf -
Blowout Preventer Systems and Well Control,” which updates standards for blowout prevention systems and other well
controls for offshore oil and gas activities conducted in US federal waters, including the Gulf of Mexico. The final rule, which
went into effect on July 28, 2016, increases the costs associated with well design, drilling and completion operations, as well as
ongoing monitoring costs for our wells in the Gulf of Mexico. More recently, pursuant to executive orders dated March 28,
2017, and April 28, 2017, the BSEE initiated a review of whether the final rule is consistent with the stated policy of
encouraging energy exploration and production, while ensuring that any such activity is safe and environmentally responsible.
On October 24, 2017, the BSEE announced - in a report published by the Department of Interior - that it is considering several
revisions to the rule and that it is in the process of determining the most effective way to engage stakeholders in the process.
Also, in April 2016, the BOEM published a proposed air quality rule that would significantly broaden the obligations of
operators and lessees in the Outer Continental Shelf, including the Gulf of Mexico, to assess, report and, when appropriate,
control emissions. Among other items, the proposed rule would expand the types of emissions that must be measured, change
the boundary for evaluating air emissions, and increase the scope of sources that must be addressed. If adopted as proposed, the
new rule would likely increase the cost associated with our activities in the Gulf of Mexico. Pursuant to the Executive Orders,
the BOEM is reviewing the proposed air quality rule. On October 24, 2017, the Department of Interior announced that it is
currently reviewing recommendations on how to proceed, including promulgating final rules for certain necessary provisions
and issuing a new proposed rule that may withdraw certain provisions and seek additional input on others.
Additionally, in order to cover the various decommissioning obligations of lessees on the OCS, the BOEM generally requires
that lessees post some form of acceptable financial assurances that such obligations will be met, such as surety bonds. The
BOEM recently updated its regulations and program oversight to establish more robust risk management, financial assurance
and loss prevention requirements for oil and gas operations in the Outer Continental Shelf, including the Gulf of Mexico. On
July 14, 2016, the BOEM issued an updated Notice to Lessees and Operators (NTL) providing details on revised procedures the
agency will be using to determine a lessee’s or operator's ability to carry out decommissioning obligations for activities in the
Outer Continental Shelf, including the Gulf of Mexico. This revised policy institutes new criteria by which the BOEM will
evaluate the financial strength and reliability of lessees and operators active in the Outer Continental Shelf. If the BOEM
determines under the revised policy that a lessee or operator does not have the financial ability to meet its decommissioning
and other obligations, that lessee or operator will be required to post additional financial security as assurance. The revised
policy originally became effective September 12, 2016; however, the BOEM extended the implementation timeline for six
months in certain circumstances. Pursuant to the Executive Orders, the BOEM is reviewing the NTL to determine whether
modifications are necessary to ensure operator compliance with lease terms while minimizing unnecessary regulatory burdens.
On June 22, 2017, the BOEM announced that, pending its review of the NTL, the implementation timeline would be
indefinitely extended, subject to certain exceptions. We estimated the impact of the new financial criteria on our operations in
the Gulf of Mexico and do not believe that the revised policy will have a material impact on our operations in the Gulf of
Mexico, or on our financial position or cash flows.
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The National Oceanic and Atmospheric Administration (NOAA) is proposing to expand the boundaries of the Flower Garden
Banks National Marine Sanctuary in the Gulf of Mexico. NOAA released its draft environmental impact statement (DEIS) on
the proposed expansion in June 2016, in which it proposed five alternatives for expanding existing sanctuary regulations to new
geographic areas. Two of these alternatives for sanctuary expansion have the potential to impact certain of our leases which
could increase drilling, operating and decommissioning costs. The comment period for the expansion alternatives outlined in
the DEIS expired on August 19, 2016 and the issuance of NOAA's report recommending alternatives is expected in early 2018.
We are currently evaluating the expansion alternatives and assessing any potential impact on our operations in the Gulf of
Mexico.
Climate Change In recent years, the EPA has finalized a series of greenhouse (GHG) gas monitoring, reporting and emissions
control rules for the oil and natural gas industry, and the US Congress has, from time to time, considered adopting legislation to
reduce emissions. In addition, almost one-half of the states have already taken measures to reduce emissions of greenhouse
gases primarily through the development of greenhouse gas emission inventories and/or regional greenhouse gas cap-and-trade
programs.
At the international level, in December 2015, the United States signed the Paris Agreement on climate change and pledged to
take efforts to reduce GHG emissions and to conserve and enhance sinks and reservoirs of GHGs. The Paris Agreement entered
into force in November 2016. However, in August 2017, the United States notified the United Nations that it would be
withdrawing from the Paris Agreement and begin negotiations to either re-enter or negotiate an entirely new agreement with
more favorable terms for the United States. While the Administration expressed a clear intent to cease implementing the Paris
Agreement, it is not clear how it plans to accomplish this goal, whether a new agreement can be negotiated, or what terms
would be included in such an agreement. Furthermore, in response to the announcement, many state and local leaders stated
their intent to intensify efforts to uphold the commitments set forth in the international accord.
The current state of development of the ongoing international climate initiatives and any related domestic actions make it
difficult to assess the timing or effect on our operations or to predict with certainty the future costs that we may incur in order
to comply with future international treaties, legislation or new regulations. However, future restrictions on emissions of GHGs,
or related measures to encourage use of renewable energy, could have a significant impact on our future operations and reduce
demand for our products. See also Items 1. and 2. Business and Properties - Regulations and Item 1A. Risk Factors.
Impact of Dodd-Frank Act Section 1504 In June 2016, the Securities and Exchange Commission (SEC) adopted resource
extraction issuer payment disclosure rules under Section 1504 of the Dodd-Frank Act that would have required resource
extraction companies, such as us, to publicly file with the SEC beginning in 2019 information about the type and total amount
of payments made to a foreign government, including subnational governments (such as states and/or counties), or the US
federal government for each project related to the commercial development of crude oil, natural gas or minerals, and the type
and total amount of payments made to each government (such rules, the Resource Extraction Issuer Payment Rules).
However, on February 14, 2017, through the signing of a joint resolution passed by the United States Congress under the
Congressional Review Act, the Resource Extraction Issuer Payment Rules were eliminated. It should be noted that Section
1504 of the Dodd-Frank Act has not been repealed and that the SEC will now have until February 2018 to issue replacement
rules to implement Section 1504 of the Dodd-Frank Act, and that under the Congressional Review Act a rule may not be issued
in “substantially the same form” as the disapproved rule unless it is specifically authorized by a subsequent law. We cannot
predict whether the SEC will issue replacement rules or, if it does so, whether such replacement rules will again be eliminated
pursuant to the Congressional Review Act.
Israel Regulatory Environment
Natural Gas Policy and Antitrust Authority The Framework, as adopted by the Government of Israel, provides clarity on
numerous matters concerning resource development, including certain fiscal, antitrust and other regulatory matters. The
Framework provides for the reduction of our ownership interest in the Tamar and Dalit fields to 25% by year-end 2021, while
enabling the marketing of Leviathan natural gas to Israeli customers. See Item 8. Financial Statements and Supplementary Data
– Note 4. Acquisitions, Divestiture and Merger.
Israeli Tax Law Effective December 21, 2016, the Israeli government decreased the corporate income tax rate from 25% to
24% for 2017 and announced a further rate decrease from 24% to 23% effective January 2018. The change decreased the
deferred tax expense for 2017 by $12 million. Furthermore, our Israeli operations are subject to the Natural Resources Profits
Taxation Law, 2011, which imposes a separate additional tax on profits from oil and gas activities (Profits Tax). See Item 8.
Financial Statements and Supplementary Data – Note 11. Income Taxes.
Hydraulic Fracturing
Hydraulic fracturing techniques have been used for decades on the majority of all new onshore crude oil and natural gas wells
drilled domestically. The process involves the injection of water, sand and chemical additives under pressure into targeted
subsurface formations to stimulate oil and gas production. We strive to adopt best practices and industry standards and comply
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with all regulatory requirements regarding well construction and operation. For example, the qualified service companies we
use to perform hydraulic fracturing, as well as our personnel, monitor rate and pressure to assure that the services are
performed as planned. Our well construction practices include installation of multiple layers of protective steel casing
surrounded by cement that are specifically designed and installed to protect freshwater aquifers by preventing the migration of
fracturing fluids into those aquifers. To help reduce our operational demand for freshwater and need for disposal, we are
currently developing technology and infrastructure to expand our water recycling capacity in the DJ and Delaware Basins. We
believe that these processes help ensure hydraulic fracturing is safe and does not and will not pose a risk to water supplies, the
environment or public health.
Although hydraulic fracturing is regulated primarily at the state level, legislation has been proposed in recent sessions of
Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of
“underground injection,” to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure
of the chemical constituents of the fluids used in the fracturing process. Furthermore, several federal agencies have asserted
regulatory authority over certain aspects of the process. For example, the EPA has taken the position that hydraulic fracturing
with fluids containing diesel fuel is subject to regulation under the Underground Injection Control program, specifically as
“Class II” Underground Injection Control wells under the Safe Drinking Water Act. In addition, the EPA previously announced
its plans to develop a Notice of Proposed Rulemaking by June 2018, which would describe a proposed mechanism - regulatory,
voluntary, or a combination of both - to collect data on hydraulic fracturing chemical substances and mixtures.
In addition, on March 26, 2015, the Bureau of Land Management (BLM) published a final rule governing hydraulic fracturing
on federal and Indian lands. The rule requires public disclosure of chemicals used in hydraulic fracturing, implementation of a
casing and cementing program, management of recovered fluids, and submission to the BLM of detailed information about the
proposed operation, including wellbore geology, the location of faults and fractures, and the depths of all usable water. On June
21, 2016, the United States District Court for Wyoming set aside the rule, holding that the BLM lacked Congressional authority
to promulgate the rule. The BLM has appealed the decision to the Tenth Circuit Court of Appeals. On March 28, 2017, an
executive order was signed, directing the BLM to review the rule and, if appropriate, to initiate a rulemaking to rescind or
revise it. Accordingly, on December 29, 2017, the BLM published a final rule to rescind the 2015 hydraulic fracturing rule.
Further legal challenges are expected. At this time, it is uncertain when, or if, the rules will be implemented, and what impact
they would have on our operations.
Furthermore, governments and agencies at all levels from federal to municipal are studying the potential environmental impacts
of hydraulic fracturing and evaluating the need for further requirements. These ongoing or proposed studies could spur
initiatives to further regulate hydraulic fracturing, and could ultimately make it more difficult or costly for us to perform
fracturing and increase our costs of compliance and doing business.
In June 2012, OSHA and the National Institute of Occupational Safety and Health (NIOSH) issued a joint hazard alert for
workers who use silica (sand) in hydraulic fracturing activities. The following year saw the agency formally propose to lower
the permissible exposure limit for airborne silica. In 2016, OSHA finalized a lower exposure limit for silica along with stricter
silica work practices. For hydraulic fracturing, the new obligations start to take effect in 2018. OSHA also has prepared
guidance identifying additional workplace hazards resulting from hydraulic fracturing and ways to reduce exposure to those
hazards.
To date, hydraulic fracturing has been regulated primarily at the state level, and all of the states where our US onshore
operations are located (including Colorado and Texas) have developed such requirements. See Regulations - Colorado and
Texas, above. Also, state and federal regulatory agencies recently have focused on a possible connection between the operation
of injection wells used for oil and gas waste disposal and seismic activity, which some have termed "induced seismicity." In a
few instances, operators of injection wells in the vicinity of seismic events have been ordered to reduce injection volumes or
suspend operations. Some state regulatory agencies have modified their regulations to account for induced seismicity with
regard to the operation of injection wells used for oil and gas waste disposal. Increased regulation and attention given to
induced seismicity in the states where we operate could lead to greater opposition, including litigation, to oil and gas activities
utilizing injection wells for waste disposal.
Several states, including Colorado and Texas, have adopted regulations requiring disclosure of certain information regarding
the components and chemicals used in the hydraulic-fracturing process. These state regulations allow disclosure through the
public registry FracFocus.org, which is operated jointly by the Interstate Oil & Gas Compact Commission and the Ground
Water Protection Council. Disclosure through the FracFocus web site includes ways to protect proprietary information and we
are currently providing disclosure information on FracFocus.org for all US onshore areas in which we operate.
Additional Information See:
Items 1. and 2. Business and Properties – Regulations;
•
Item 1A. Risk Factors; and
•
• Risk and Insurance Program.
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Risk and Insurance Program
As protection against financial loss resulting from many, but not all operating hazards, we maintain insurance coverage,
including certain physical damage, business interruption (loss of production income), employer's liability, third party liability,
worker's compensation insurance and certain insurance related to cyber security. We maintain insurance at levels that we
believe are appropriate and consistent with industry practice and we regularly review our potential risks of loss and the cost and
availability of insurance and the company's ability to sustain uninsured losses, and revise our insurance program accordingly.
Availability of insurance coverage, subject to customary deductibles and recovery limits, for certain perils such as war or
political risk is often excluded or limited within property policies. In Israel and Equatorial Guinea, we insure against acts of
war and terrorism in addition to providing insurance coverage for normal operating hazards facing our business. Additionally,
as being part of critical national infrastructure, the Israel offshore and onshore assets are included in a special property coverage
afforded under the Israeli government's Property Tax and Compensation Fund Law; however, the amount of financial recovery
through the fund is not guaranteed.
We have a risk assessment program that analyzes safety and environmental hazards, including cyber threats, and establishes
procedures, work practices, training programs and equipment requirements, including monitoring and maintenance rules, for
continuous improvement. We also use third party consultants to help us identify and quantify our risk exposures at major
facilities. We have a robust prevention program and continue to manage our risks and operations such that we believe the
likelihood of a significant event is remote. However, if an event occurs that is not covered by insurance, not fully protected by
insured limits or our non-operating partners are not fully insured, it could have a material adverse impact on our financial
condition, results of operations and cash flows. See Item 1A. Risk Factors.
Undeveloped Oil and Gas Leases
Oil and gas exploration is a lengthy process of obtaining data, evaluating, and de-risking prospects, and it takes time to develop
resources in a responsible manner. The period of time from lease acquisition to discovery can take many years of ongoing
effort.
We begin by leasing acreage (or deepwater lease blocks) from individuals, other operators or the host government. It may take
years for us to assemble sufficient acreage to cover the areal extent of a prospect that we wish to explore.
Once the acreage position is assembled, we obtain seismic data either through purchase of available data or by contracting for
seismic services. Our exploration staff then begin a lengthy process of analyzing the seismic and other data in order to identify
a potential optimal location for drilling an initial exploratory well. Once we decide to drill an exploratory well, we must obtain
permits and contract a drilling rig with the specifications for the depth and well pressures which we expect to drill.
If there is a discovery, we may need to obtain additional data and/or drill appraisal wells in order to estimate the extent of the
reservoir and the volume of resources that could potentially be recovered. Appraisal or development drilling requires additional
time to contract for an appropriate drilling rig, and obtain pipe, other equipment, and supplies.
Competition
The crude oil and natural gas industry is highly competitive. We encounter competition from other crude oil and natural gas
companies in all areas of operations, including the acquisition of seismic data and lease rights on crude oil and natural gas
properties and for the labor and equipment required for exploration and development of those properties. Our competitors
include major integrated crude oil and natural gas companies, state-controlled national oil companies, independent crude oil
and natural gas companies, service companies engaging in exploration and production activities, drilling partnership programs,
private equity, and individuals. Many of our competitors are large, well-established companies. Such companies may be able to
pay more for seismic information and lease rights on crude oil and natural gas properties and exploratory prospects and to
define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources
permit. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to
evaluate and select suitable properties and to consummate transactions in a highly competitive environment. See Item 1A. Risk
Factors.
Employees
As of December 31, 2017, we had 2,277 full-time employees.
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Offices
Our principal corporate office is located at 1001 Noble Energy Way, Houston, Texas, 77070. We maintain additional regional
exploration and/or production offices primarily in Denver, Colorado; Greeley, Colorado; Pecos, Texas; Dilley, Texas; and in
Israel, Cyprus, and Equatorial Guinea.
Title to Properties
We believe that our title to the various interests set forth above is satisfactory and consistent with generally accepted industry
standards, subject to exceptions that would not materially detract from the value of the interests or materially interfere with
their use in our operations. Individual properties may be subject to burdens such as royalty, overriding royalty and other
outstanding interests customary in the industry. In addition, interests may be subject to obligations or duties under applicable
laws or burdens such as production payments, net profits interest, liens incident to operating agreements and for current taxes,
development obligations under crude oil and natural gas leases or capital commitments under PSCs or exploration licenses. We
have also dedicated certain of our US onshore acreage to Noble Midstream Partners for the provision of midstream services to
us.
Furthermore, while the majority of our assets are held by production, certain of our assets, such as our Eagle Ford Shale and
Delaware Basin properties, are held through continuous development obligations. Therefore, we are contractually obligated to
fund a level of development activity in these areas and failure to meet these obligations may result in the loss of a lease.
Title Defects Subsequent to a lease or fee interest acquisition transaction, the buyer usually has a period of time in which to
examine the leases for title defects. Adjustments for title defects are generally made within the terms of the sales agreement,
which may provide for arbitration between the buyer and seller.
Conflicts with Surface Rights Mineral rights are property rights that include the right to use land surface that is reasonably
necessary to access minerals beneath. Lawsuits regarding conflicts between surface rights and mineral rights are currently
pending in several states. In several cases, owners of surface rights are suing various companies to prevent companies from
using their land surface to drill horizontal wells to explore for or produce hydrocarbons from neighboring mineral tracts. If a
plaintiff were to prevail in such a case, it could become more difficult and expensive for a company to place multi-acre well
pads and/or limit the length of horizontal wells drilled from a pad.
Available Information
Our website address is www.nblenergy.com. Available on this website under “Investors – Financial Information – SEC Filings,”
free of charge, are our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy
statements, Forms 3, 4 and 5 filed on behalf of directors and executive officers and amendments to those reports as soon as
reasonably practicable after such materials are electronically filed with or furnished to the SEC. Alternatively, you may access
these reports at the SEC’s website at www.sec.gov.
Also posted on our website under “Our Story – Transparency – Corporate Governance - Committee Charters”, and available in
print upon request made by any stockholder to the Investor Relations Department, are charters for our Audit Committee,
Compensation, Benefits and Stock Option Committee, Corporate Governance and Nominating Committee, and Environment,
Health and Safety Committee. Copies of the Code of Conduct and the Code of Ethics for Chief Executive and Senior Financial
Officers (the Codes) are also posted on our website under the “Other Governance Documents” section. Within the time period
required by the SEC and the NYSE, as applicable, we will post on our website any modifications to the Codes and any waivers
applicable to senior officers as defined in the applicable Code, as required by the Sarbanes-Oxley Act of 2002.
Item 1A. Risk Factors
Described below are certain risks that we believe are applicable to our business and the oil and gas industry in which we operate.
There may be additional risks that are not presently material or known. You should carefully consider each of the following risks
and all other information set forth in this Annual Report on Form 10-K.
If any of the events described below occur, our business, financial condition, results of operations, cash flows, liquidity or
access to the capital markets could be materially adversely affected. In addition, the current global economic and political
environment intensifies many of these risks.
The oil and gas industry is cyclical and an extended period of suppressed commodity prices could have material adverse
effects on our operations, our liquidity, and the price of our common stock.
Our ability to operate profitably, maintain adequate liquidity, grow our cash flow and pay dividends on our common stock
depend upon the prices we receive for our crude oil, natural gas, and NGL production. Commodity prices are cyclical and
subject to supply and demand dynamics. For the past three years, following the significant decline that began in late 2014,
crude oil prices, in particular, have been trading in a much lower range. While we have witnessed a certain degree of
commodity price improvement, we expect that economic, geopolitical, and supply and demand forces will remain volatile. As a
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result we may continue to operate in a soft market, with sustained lower commodity prices, subject to further decline if the
excess of supply over demand increases.
If commodity prices continue to trade at low or lower levels for an extended period, one or more of the following could occur:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
significant reductions of our revenues, profit margins, operating income and cash flows;
reduction in the amount of crude oil, natural gas and NGLs that we can produce economically, leading to shut-in or
early abandonment of producing wells and increased capital requirements for abandonment operations;
certain properties in our portfolio becoming economically unviable;
impairments of proved or unproved properties or other long-lived assets;
loss of undeveloped acreage if our production is shut-in or we are unable to make scheduled delay rental payments;
use of cash flow to satisfy minimum obligations under throughput agreements if production is suspended;
reduction, or suspension, of our 2018 or future capital investment programs, resulting in a reduced ability to develop
our reserves;
delay, postponement or cancellation of some of our exploration or development projects;
inability to meet exploration commitments, leading to loss of leases or exploration rights;
divestments of properties to generate funds to meet cash flow or liquidity requirements;
limitations on our financial condition, liquidity, including access to sources of capital, such as debt and equity, and/or
ability to finance planned capital expenditures and operations;
failure of our partners to fund their share of development costs or obtain financing could result in delay or cancellation
of future projects, thus limiting our growth and future cash flows;
inability to meet scheduled interest and/or debt payments or payments due under operating or capital leases;
a series of credit rating downgrades or other negative rating actions which could increase our cost of financing and
may increase our requirements to post collateral as financial assurance of performance under certain other contracts
which, in turn, could have a negative impact on our liquidity;
changes in corporate structure that could lead to loss of key personnel and interrupt our business activities; and
reduction or suspension of dividends on our common stock.
In addition, lower commodity prices, including declines in commodity forward price curves, may result in the following:
•
•
•
declines in our stock price;
additional counterparty credit risk exposure on commodity hedges and joint venture receivables; and
a reduction in the carrying value of goodwill.
Our hedging arrangements in place will not fully mitigate the effects of commodity price volatility.
Furthermore, certain crude oil demand estimates suggest a hypothetical point in the future when global oil demand reaches its
peak demand level. The International Energy Agency's 450 Scenario sets out an energy pathway consistent with the goal of
limiting the global increase in temperature to 2°C by limiting concentration of greenhouse gases in the atmosphere to around
450 parts per million of CO2. Under this scenario, global oil demand peaks by 2020, and the subsequent decline in demand
accelerates year-on-year, so that by the late 2020s global demand is falling by over one million barrels per day every year. This
decline in demand, if it occurs, would negatively impact commodity prices as well as our ability to explore for and develop our
crude oil and natural gas resources.
Markets and prices for crude oil, natural gas and NGLs depend on factors beyond our control, factors including, among others:
•
•
•
•
•
•
•
•
•
•
global demand for crude oil, natural gas and NGLs as impacted by economic factors that affect gross domestic product
growth rates of countries around the world;
global supply for crude oil, natural gas and NGLs as impacted by OPEC and non-OPEC countries (e.g. US, Russia,
Canada);
technology advances that increase crude oil, natural gas and NGL production, thereby increasing supply;
new technologies that promote fuel efficiency and reduce energy consumption;
developments in the global LNG market, including exports from the US;
geopolitical conditions and events, including generational leadership or regime changes, changes in government
energy policies, including imposed price controls and/or product subsidies, or instability/armed conflict in
hydrocarbon-producing regions;
fluctuations in US dollar exchange rates, the currency in which the world's crude oil trade is generally denominated;
the price and availability of alternative fuels, including coal, solar, wind, nuclear energy and biofuels, as well as the
availability of battery storage;
the long-term impact on the crude oil market of the use of natural gas and electricity as an alternative fuel for road
transportation or the use of natural gas as fuel for electricity generation impacting the demand for electricity;
fuel efficiency regulations, such as the Corporate Average Fuel Economy (CAFE) standards, and its impacts on
demand for crude oil as a transportation fuel;
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•
•
•
• weather conditions;
•
•
the availability of pipeline capacity/infrastructure as well as refining capacity;
the level and effect of trading in commodity futures markets, including by commodity price speculators and others;
the effectiveness of worldwide conservation measures;
access to government-owned and other lands for exploration and production activities; and
domestic and foreign governmental regulations and taxes.
Sector cost inflation could adversely affect our ability to execute our exploration and development plans on a timely basis
and within our budget.
Our industry is cyclical and third party oilfield materials, service and supply costs are also subject to supply and demand
dynamics. During periods of decreasing levels of industry exploration and production, the demand for, and cost of, drilling rigs
and oilfield services decreases. Conversely, during periods of increasing levels of industry activity, the demand for, and cost of,
drilling rigs and oilfield services increases.
During 2017, increases in US onshore drilling and completion activity resulted in higher demand for oilfield services. As a
result, the costs of drilling, equipping and operating wells and infrastructure began to experience some inflation. If this trend
continues, and if the commodity price recovery is robust, we expect industry exploration and production activities to continue
to increase, resulting in even higher demand for oilfield services and supplies, which could result in significant sector price
inflation. In addition, the costs of such items could increase and their availability may become limited, particularly in basins of
relatively higher activity. Potential scarcity of competent service personnel may impact our ability to execute our exploration
and development plans in a timely and profitable manner.
In addition, regulatory changes, such as those related to hydraulic fracturing or water disposal, may also result in reduced
availability and/or higher costs for rigs and services. As a result, drilling rigs and oilfield services may not be available at rates
that provide a satisfactory return on our investment.
Our international operations may be adversely affected by economic and geopolitical developments.
We have significant international operations, with approximately 27% of our 2017 total consolidated sales volumes and
approximately 52% of our total proved reserves as of December 31, 2017 attributable to our international operations in Israel
and Equatorial Guinea. We also conduct exploration activities in other international areas. Our operations may be adversely
affected by political and economic developments, including the following:
•
•
•
•
•
•
•
renegotiation, modification or nullification of existing contracts, such as may occur pursuant to future regulations
enacted as a result of changes in Israel's antitrust, export and natural gas development policies, or the hydrocarbons
law enacted in 2006 by the government of Equatorial Guinea, which can result in an increase in the amount of
revenues that the host government receives from production (government take) or otherwise decrease project
profitability;
loss of revenue, property and equipment as a result of actions taken by host nations, such as expropriation or
nationalization of assets or termination of contracts;
disruptions caused by territorial or boundary disputes in certain international regions;
changes in drilling or safety regulations;
laws and policies of the US and foreign jurisdictions affecting trade, foreign investment, taxation and business
conduct;
potential for Israel natural gas production and regional exports to be interrupted by political conditions and events, and
regional instability or armed conflict in the region;
difficulties enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and
foreign sovereignty over international operations;
• US and international monetary policies impacting foreign exchange or repatriation restrictions in countries in which
we conduct business;
• war, piracy, acts of terrorism or civil unrest; and
•
other hazards arising out of foreign governmental sovereignty over areas in which we conduct operations.
Such political and economic developments could have a negative impact on our results of operations and cash flows and reduce
the fair values of our properties, resulting in impairment charges.
Our operations may be adversely affected by changes in the fiscal regimes and related government policies and regulations
in the countries in which we operate.
Fiscal regimes impact oil and gas companies through laws and regulations governing resource access along with government
participation in oil and gas projects, royalties and taxes. We operate in the US and other countries whose fiscal regimes may
change over time. Changes in fiscal regimes result in an increase or decrease in the amount of government financial take from
developments, and a corresponding decrease or increase in the revenues of an oil and gas company operating in that particular
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country. For example, a significant portion of our production comes from Israel and Equatorial Guinea; therefore, changes in
or uncertainties related to the fiscal regimes of these countries could have a significant impact on our operations and financial
performance. Further, we cannot predict how government agencies or courts will interpret existing regulations and tax laws or
the effect such interpretations could have on our business.
Many governments globally are seeking additional revenue sources, including, potentially, increases in government financial
take from oil and gas projects. In developing nations, governments may seek additional revenues to support infrastructure and
economic development and for social spending. In many nations of the Organisation for Economic Cooperation and
Development (OECD), governments continue to incur significant budget deficits and growing national debt levels, as well as
pressure from financial markets to address structural spending imbalances.
The OECD Base Erosion and Profit Sharing (BEPS) initiative aims to standardize and modernize global tax policy and
disclosure of financial and operational data with tax authorities. The BEPS's recommendations are being widely adopted by the
majority of the foreign jurisdictions in which we operate and many of these jurisdictions are party to the Multilateral
Convention to Implement Tax Treaty Related Measures to Prevent Base Erosion and Profit Shifting. Progress on the
implementation of BEPS measures and development of tax authority interpretation could result in changes to tax policies,
including transfer pricing policies. To the extent such changes significantly increase the overall tax imposed on currently
producing projects, these projects could become less economic, or wholly uneconomic, thereby reducing the amount of proved
reserves we record and cash flows we receive, and possibly resulting in asset impairment charges.
Changes in fiscal regimes have long-term impacts on our business strategy, and fiscal uncertainty makes it difficult to formulate
and execute capital investment programs. The implementation of new, or the modification of existing, laws or regulations
increasing the tax costs on our business could disrupt our business plans and negatively impact our operations and our stock
price in the following ways, among others:
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restrict resource access or investment in lease holdings;
limit or cancel exploration and/or development activities, which could have a long-term negative impact on the
quantities of proved reserves we record and inhibit future production growth;
have a negative impact on the ability of us and/or our partners to obtain financing;
reduce the profitability of our projects, resulting in decreases in net income and cash flows with the potential to make
future investments uneconomical;
result in currently producing projects becoming uneconomic, to the extent fiscal changes are retroactive, thereby
reducing the amount of proved reserves we record and cash flows we receive, and possibly resulting in asset
impairment charges;
require that valuation allowances be established against deferred tax assets, with offsetting increases in income tax
expense, resulting in decreases in net income and cash flow; and/or
restrict our ability to compete with imported volumes of crude oil or natural gas.
Tax laws and regulations may change over time, and could adversely affect our business and financial condition.
On December 22, 2017, the US Congress enacted the Tax Cuts and Jobs Act (Tax Reform Legislation). The Tax Reform
Legislation, among other things, (i) permanently reduces the US corporate income tax rate to 21% beginning in 2018, (ii)
repeals the corporate alternative minimum tax (AMT) allowing for corresponding refunds of prior period AMT credits, (iii)
provides for a five year period of 100% bonus depreciation followed by a phase-down of the bonus depreciation percentage,
(iv) imposes a new limitation on the utilization of net operating losses generated in taxable years beginning after December 31,
2017, and (v) provides for more general changes to the taxation of corporations, including changes to the deductibility of
interest expense, the adoption of a modified territorial tax system, assessing a repatriation tax or “toll-charge” on undistributed
earnings and profits of US-owned foreign corporations, and introducing certain anti-base erosion provisions. The Tax Reform
Legislation is complex and far-reaching and could eliminate or postpone certain tax deductions that currently are available with
respect to oil and gas development, or increase costs. The ultimate impact of the Tax Reform Legislation may differ from our
estimates due to changes in interpretations and assumptions made by us as well as additional regulatory guidance that may be
issued, and our business and financial condition could be adversely affected.
In addition, from time to time, legislation has been proposed that, if enacted into law, would make significant changes to US
federal and state income tax laws, including (i) the elimination of the immediate deduction for intangible drilling and
development costs, (ii) the repeal of the percentage depletion allowance for oil and natural gas properties; and (iii) an extension
of the amortization period for certain geological and geophysical expenditures. While these specific changes are not included in
the Tax Reform Legislation, no accurate prediction can be made as to whether any such legislative changes will be proposed or
enacted in the future, or the timing of any such action. The elimination of such US federal tax deductions, as well as any other
changes to or the imposition of new federal, state, local or non-US taxes (including the imposition of, or increases in
production, severance or similar taxes) could adversely affect our business and financial condition.
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We are subject to increasing governmental regulations and environmental requirements that may cause us to incur
substantial incremental costs.
Our industry is subject to complex laws and regulations adopted or promulgated by international, federal, state and local
authorities relating to the exploration for, and the development, production and marketing of, crude oil, natural gas and NGLs.
As the various government and/or regulatory bodies issue or rescind various regulations, our operations are subject to
significant volatility in response to the issuance, interpretation and application of these regulations.
Changes in price controls, taxes and environmental laws relating to our industry have the ability to substantially affect crude
oil, natural gas and NGL production, operations and economics. Environmental laws, in particular, can change frequently, often
become stricter and at times may force us to incur additional costs as changes are implemented.
We cannot always predict with certainty how agencies or courts will interpret existing laws and regulations or the effect these
interpretations may have on our business or financial condition.
Additionally, the unintentional discharge of natural gas, crude oil, or other pollutants into the air, soil or water may give rise to
liabilities on our part to government agencies and/or third parties, and may require us to incur costs to achieve remediation
objectives and/or requirements.
In April 2015, for example, we entered into a Consent Decree with the US EPA, US Department of Justice and State of
Colorado to improve emission control systems at a number of our condensate storage tanks in the DJ Basin. The Consent
Decree required us to pay a civil penalty and to perform certain injunctive relief activities, mitigation projects, and
supplemental environmental projects. We continue to incur costs associated with these activities. In addition, compliance with
the Consent Decree could result in the temporary shut in or permanent plugging and abandonment of certain wells and
associated tank batteries within the Non-Attainment Area of the DJ Basin.
Noncompliance with existing or future legislation or regulations could potentially result in an increased risk of civil or criminal
fines or sanctions. For example, fines or sanctions associated with a well incident or spill could well exceed the actual cost of
containment and cleanup.
Further expansion of environmental, safety and performance regulations or an increase in liability for drilling or production
activities, including punitive fines, may have one or more of the following impacts on our business:
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increase the costs of drilling exploratory and development wells;
cause delays in, or preclude, the development of our projects resulting in longer development cycle times;
result in additional operating and capital costs;
divert our cash flows from capital investments in order to maintain liquidity;
increase or remove liability caps for claims of damages from oil spills;
increase our share of civil or criminal fines or sanctions for actual or alleged violations if a well incident were to
occur; and
limit our ability to obtain additional insurance coverage, at a level that balances the cost of insurance and our desired
rates of return, to protect against any increase in liability.
Any of the above operating or financial factors may result in a reduction of our cash flows, profitability, and the fair value of
our properties or reduce our financial flexibility. Because we strive to achieve certain levels of return on our projects, an
increase in our financial responsibility could result in certain of our planned projects becoming uneconomic. See Items 1. and
2. Business and Properties – Regulations.
We face various risks associated with global populism and general political uncertainty.
Following the 2008/2009 global financial crisis, the world has experienced lower economic growth versus the levels attained in
previous decades. This has resulted in economic stagnation for certain citizens and, as a result, there are concerns around jobs,
economic well-being and wealth distribution. Globally, certain individuals and organizations are attempting to focus the
public's attention on income and wealth distribution and implement income and wealth redistribution policies.
In addition, if efforts to challenge and change individual and/or corporate taxation are successful, they could result in increased
taxation on individuals and/or corporations, as well as, potentially, increased regulation on companies and financial institutions.
These measures would further burden companies and individuals with additional tax costs.
Recent events have intensified these risks. In the US, the growing trends toward populism and political polarization, has
resulted in uncertainty regarding potential changes in regulations, fiscal policy, social programs, domestic and foreign relations
and international trade policies. Global uncertainty and/or reductions in global trade activities could contribute to slower
economic growth which could negatively impact business and commerce.
Potential changes in relationships among the US, China and Russia, or among China, Russia and other countries, can have
significant impacts on the balance of power, as well as on global trade, with further impacts on both global and local
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economies. In addition, changes in the relationships between the US and its neighbors, such as Mexico, can have significant,
potentially negative, impacts on commerce. In Europe, the populist movement has resulted in the Brexit vote and increasing
populist demands and rises in nationalism could have a negative impact on economic policy and consequently pose a potential
threat to the unity of the European Union.
Our ability to respond to these developments or comply with any resulting new legal or regulatory requirements, including
those involving economic and trade sanctions, as well as any potential increased tax expense, could reduce our ability to
negotiate the sale of our products, increase our costs of doing business, reduce our financial flexibility and otherwise have a
material adverse effect on our business, financial condition and results of our operations.
We face various risks associated with the trend toward increased anti-oil and gas development activity.
In recent years, we have seen significant growth in opposition to oil and gas development both in the US and globally.
Companies in our industry can be the target of opposition to hydrocarbon development from stakeholder groups, including
national, state and local governments, regulatory agencies, non-government organizations and public citizens. This opposition
is focused on attempting to limit or stop hydrocarbon development. Examples of such opposition include: efforts to reduce
access to public and private lands; delaying or canceling permits for drilling or pipeline construction; limiting or banning
industry techniques such as hydraulic fracturing, and/or adding restrictions on or the use of water and associated disposal;
imposition of set-backs on oil and gas sites; delaying or denying air-quality permits; advocating for increased regulations,
punitive taxation, or citizen ballot initiatives or moratoriums on industry activity; and the use of social media channels to cause
reputational harm. We have experienced these efforts in Colorado in the past and it is likely they will continue into the future.
Recent efforts by the US Administration to modify federal oil and gas related regulations could intensify the risk of anti-
development efforts from grass roots opposition.
Our need to incur costs associated with responding to these anti-development efforts, including legal challenges, or complying
with any new legal or regulatory requirements resulting from these efforts, could have a material adverse effect on our business,
financial condition and results of operations.
Restricted land access could reduce our ability to explore for and develop crude oil, natural gas and NGL reserves.
Our ability to adequately explore for and develop crude oil, natural gas and NGL resources is affected by a number of factors
related to access to land. Examples of factors which reduce our access to land include, among others:
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new municipal, state or federal land use regulations, which may restrict drilling locations or certain activities such as
hydraulic fracturing;
local and municipal government control of land or zoning requirements, which can conflict with state law and deprive
land owners of property development rights;
landowner, community and/or governmental opposition to infrastructure development;
regulation of federal and Indian land by the BLM;
anti-development activities, which can reduce our access to leases through legal challenges or lawsuits, disruption of
drilling, or damage to equipment;
the presence of threatened or endangered species or of their habitat;
disputes regarding leases; and
disputes with landowners, royalty owners, or other operators over such matters as title transfer, joint interest billing
arrangements, revenue distribution, or production or cost sharing arrangements.
Loss of access to land for which we own mineral rights could result in a reduction in our proved reserves and a negative impact
on our results of operations and cash flows. Reduced ability to obtain new leases could constrain our future growth and
opportunity set by limiting the expansion of our upstream portfolio. In addition, loss of rights granted under surface use
agreements, rights-of-way, surface leases or other easement rights, could disrupt or prohibit our ability to construct or operate
midstream assets and could have a material adverse effect on our business, financial condition, results of operations, and cash
flows.
A change in international and/or US federal and state climate policy could have a significant impact on our operations and
profitability.
Domestic and international response to climate and related energy issues are matters of public policy consideration. We are
currently in a period of increasing uncertainty as to these matters, and, at this time, it is difficult to anticipate how the current
US Administration, or other entities, may act on exiting or new laws and regulations. As compared with certain large multi-
national, integrated energy companies, we do not conduct fundamental research regarding the scientific inquiry of climate
change. However, we will continue to closely monitor all relevant developments in this regard. Changes in international,
federal or state laws and regulations regarding climate policy could have a significant negative impact on our ability to explore
for and develop crude oil and natural gas resources or reduce demand for our products.
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In recent years, international, federal, state and local governments have taken steps to reduce emissions of greenhouse gases.
The EPA has finalized a series of greenhouse gas monitoring, reporting and emissions control rules for the oil and natural gas
industry, and the US Congress has, from time to time, considered adopting legislation to reduce emissions. Almost one-half of
states in the US have taken measures to reduce emissions of greenhouse gases primarily through the development of
greenhouse gas emission inventories and/or regional greenhouse gas cap-and-trade programs. For a description of existing and
proposed greenhouse gas rules and regulations, see Items 1. and 2. Business and Properties - Regulations.
In addition, claims have been made against certain energy companies alleging that greenhouse gas emissions from oil and
natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or
other entities may make claims against us for alleged personal injury, property damage, or other potential liabilities. While our
business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in
any such case could impact our operations and could have an adverse impact on our financial condition.
Moreover, there has been public discussion that climate change may be associated with extreme weather conditions such as
more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible
consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could
cause some areas to experience temperatures substantially hotter or colder than their historical averages. Extreme weather
conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be
fully insured.
Our Eastern Mediterranean discoveries bear certain geopolitical, regulatory, financial and technical challenges that could
adversely impact our ability to monetize these natural gas assets.
We have entered into and are currently negotiating various long-term GSPAs for our Eastern Mediterranean natural gas assets.
Some of these agreements would require the export of natural gas from either Israel or Cyprus to other countries in the region,
such as Egypt and Jordan. These agreements are subject to a variety of risks, including geopolitical, regulatory, financial and
other uncertainties. War, political violence, civil unrest or lack of intergovernmental cooperation could affect both our and our
counterparties’ abilities to cooperate and to perform under these agreements, and could potentially lead to a breach or
termination of such agreements. In addition, economic conditions or financial duress of our counterparties could jeopardize
their ability to fulfill their payment obligations under these contracts. Furthermore, if material disruptions occur, including
events or circumstances constituting force majeure under contract provisions, such that they inhibit us or our counterparties
from performing under these GSPAs, or our counterparties are unable to pay us for a sustained period of time, we could incur
significant financial losses. While the State of Israel continues to maintain its ability to generate electricity via coal-fired power
plants, as they transition from coal-fired power plants to natural gas-fired power plants, they become more dependent on us and
our partners for their source of natural gas supply. Any material disruption in our ability to deliver natural gas to the State of
Israel could have a material impact on our expected profitability, financial performance and reputation.
We are subject to certain regulatory provisions under the Framework, as adopted by the Government of Israel, including a
requirement to reduce our ownership in the Tamar and Dalit fields to 25% by the end of 2021. We recently signed a definitive
agreement to divest a 7.5% working interest in each of the fields to Tamar Petroleum Ltd., closing of the transaction is subject
to satisfactory conclusion of certain conditions, including Tamar Petroleum's debt financing. Upon closing, we will receive
consideration of both cash and Tamar Petroleum Ltd. shares, approximating 70% and 30%, respectively, of the transaction
value, which will fluctuate based on market conditions. In accordance with the Framework, we must divest Tamar Petroleum
Ltd. shares received by the end of 2021. In addition, changes in Israel's fiscal and/or regulatory regimes or energy policies
occurring as a result of government policy on natural gas development and/or exports could delay or reduce the profitability of
our Tamar and/or Leviathan development projects, and/or render future exploration and development projects uneconomic.
Development of our Eastern Mediterranean natural gas assets requires substantial investment and will take several years to
complete. Our partners must be able to fund their share of investment costs through the development cycle, through cash flow
from operations, external credit facilities, or other sources, including financing arrangements. If our project partners' cash flows
or ability to maintain adequate financing are negatively impacted through similar risks factors described herein, the
development of a project could be delayed and the timing and receipt of planned cash flows and expected profitability could be
negatively impacted.
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Due to the scale of our Leviathan (Israel) and Aphrodite (Cyprus) discoveries, realization of their full economic value depends
on our ability to execute successful phased, development scenarios, the failure or delay of which could reduce our future
growth and have negative effects on our future operating results. Offshore projects of this magnitude entail significant technical
complexities including subsea tiebacks to a FPSO or production platform, pressure maintenance systems, gas re-injection
systems, onshore receiving terminals, or other specialized infrastructure. In addition, we depend on third-party technology and
service providers and other supply chain participants for these complex projects. Delays and differences between estimated and
actual timing of critical events related to these projects could have a material adverse effect on our results of operations.
Concentration of capital in, and production and cash flows from, certain operations may increase our exposure to risks
enumerated herein.
A significant portion of our production and revenues is highly concentrated and is generated from a limited number of
conventional deepwater wells. These wells, located in the Gulf of Mexico, offshore Israel and offshore Equatorial Guinea,
contributed approximately 33% of our 2017 total consolidated revenues and 34% of our 2017 total consolidated sales volumes.
In addition, with the recording of reserves associated with the initial development of the Leviathan field, we now have a major
concentration of reserves offshore Israel, with approximately 47% of our year-end 2017 proved reserves attributable to this
area. These fields are also capital and resource-intensive.
Although we carry contingent business interruption for these producing assets, as well as other insurance, the insurance may be
insufficient to cover all of risks including, a disruption to downstream operations impacting the processing, marketing and
distribution of our production, such as from an accident, natural disaster, government intervention or other event, would have a
significant impact on our production profile, cash flows, profitability, and overall business plan.
We also have significant concentrations of capital and production in unconventional basins including the DJ Basin, Delaware
Basin and Eagle Ford Shale, and we expect to invest approximately 65%, of our total capital investment program to
development activities in these areas in 2018. Restrictions in land access, rapid changes in drilling and completion technology,
significant increases in drilling and completion costs, lack of availability of downstream services, changes in regulations and
other risks impacting these areas, as enumerated in certain risk factors described herein, can have immediate, significant
negative impacts on our production, cash flows, profitability and financial position.
A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss.
We depend on digital technology, including information systems and related infrastructure as well as cloud applications and
services, to process and record financial and operating data, communicate with our employees and business partners, analyze
seismic and drilling information, estimate quantities of oil and gas reserves as well as other activities related to our business.
Our business partners, including vendors, service providers, purchasers of our production, and financial institutions, are also
dependent on digital technology. The technologies needed to conduct oil and gas exploration and development activities in
deepwater, ultra-deepwater and shale, as well as technologies supporting midstream operations and global competition for oil
and gas resources make certain information the target of theft or misappropriation.
As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, also
has increased. A cyber attack could include gaining unauthorized access to digital systems for purposes of misappropriating
assets or sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites.
SCADA-based systems are potentially vulnerable to targeted cyber attacks due to their critical role in operations.
Our technologies, systems, networks, and those of our business partners may become the target of cyber attacks or information
security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary
and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance,
may remain undetected for an extended period.
Our implementation of various controls and processes to monitor and mitigate security threats and to increase security for our
information, facilities and infrastructure is costly and labor intensive. Moreover, there can be no assurance that such measures
will be sufficient to prevent security breaches from occurring. As cyber threats continue to evolve, we may be required to
expend significant additional resources to continue to modify or enhance our protective measures or to investigate and
remediate any information security vulnerabilities.
Our operations may be adversely affected by violent acts such as from civil disturbances, terrorist acts, regime changes,
cross-border violence, war, piracy, or other conflicts that may occur in regions that encompass our operations.
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Certain regions, such as the Middle East and Africa, continue to experience varying degrees of political instability, public
protests and terrorist attacks. We operate in regions of the world that have experienced such incidents or are in close proximity
to areas where violence has occurred. Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as
military or other actions taken in response to these acts, could cause instability in the global financial and energy markets.
Continued or escalated civil and political unrest and acts of terrorism in the regions in which we operate could result in
curtailment of our operations. In the event that regions in which we operate experience civil or political unrest or acts of
terrorism, especially in areas where such unrest leads to regime change, our operations in such regions could be materially
impaired.
We monitor the economic and political environments of the countries in which we operate. However, we are unable to predict
the occurrence of disturbances such as those noted above. In addition, we have limited ability to mitigate their impact.
Civil disturbances, terrorist acts, regime changes, war, or conflicts, or the threats thereof, could have the following results,
among others:
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increased volatility in global crude oil, natural gas and NGL prices which could negatively impact the global economy,
resulting in slower economic growth rates, which could reduce demand for our products;
negative impact on the global crude oil supply if infrastructure or transportation are disrupted, leading to further
commodity price volatility;
difficulty in attracting and retaining qualified personnel to work in areas with potential for conflict;
inability of our personnel or supplies to enter or exit the countries where we are conducting operations;
disruption of our operations due to evacuation of personnel;
inability to deliver our production due to disruption or closing of transportation routes;
reduced ability to export our production due to efforts of countries to conserve domestic resources;
damage to or destruction of our wells, production facilities, receiving terminals or other operating assets;
damage to or destruction of property belonging to our natural gas purchasers leading to interruption of natural gas
deliveries, claims of force majeure, and/or termination of natural gas sales contracts, resulting in a reduction in our
revenues;
inability of our service and equipment providers to deliver items necessary for us to conduct our operations;
lack of availability of drilling rigs, oilfield equipment or services if third party providers decide to exit the region;
shutdown of a financial system, communications network, or power grid causing a disruption to our business
activities; and
capital market reassessment of risk and reduction of available capital making it more difficult for us and our partners
to obtain financing for potential development projects.
Loss of property and/or interruption of our business plans resulting from civil unrest could have a significant negative impact
on our earnings and cash flow. In addition, we may not have enough insurance to cover any loss of property or other claims
resulting from these risks.
Exploration, development and production activities carry inherent risk. These activities, as well as natural disasters or
adverse weather conditions, could result in liability exposure or the loss of production and revenues.
Our crude oil and natural gas operations are subject to hazards and risks inherent in the drilling, production and transportation
of crude oil, natural gas and NGLs, including:
pipeline ruptures and spills;
fires, explosions, blowouts and well cratering;
equipment malfunctions and/or mechanical failure on high-volume, high-impact wells;
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other facilities and equipment utilized in support of our crude oil, natural gas and NGL operations;
leaks or spills occurring during the transfer of hydrocarbons from an FPSO to an oil tanker;
loss of product occurring as a result of transfer to a rail car or train derailments;
formations with abnormal pressures and basin subsidence which could result in leakage or loss of access to
hydrocarbons;
release of pollutants; and
spills, leaks or discharges of fluids used in or produced in the course of operations, especially those that reach surface
water or groundwater.
Some of these risks or hazards could materially and adversely affect our revenues and expenses by reducing or shutting in
production from wells, loss of equipment or otherwise negatively impacting the projected economic performance of our
projects. In addition, our ability to deliver product pursuant to long-term supply contracts could be negatively impacted
resulting in additional financial exposure in the event we cannot fully deliver the contract quantities.
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Any of these risks or hazards can result in injuries and/or deaths of employees, supplier personnel or other individuals, loss of
hydrocarbons, environmental pollution and other damage to our properties or the properties of others, regulatory investigations
and administrative, civil and criminal penalties or restricted access to our properties.
In addition, our operations and financial results could be significantly impacted by adverse weather conditions and natural
disasters in the areas we operate including:
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hurricanes, tropical storms, cyclones, windstorms, or “superstorms” which could affect our operations in areas such as
Texas and the Gulf of Mexico;
• winter storms and snow which could affect our operations in the DJ Basin;
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extremely high temperatures, which could affect third party gathering and processing facilities in the DJ Basin and
Texas;
severe droughts resulting in new restrictions on water usage in the DJ Basin and Texas;
harsh weather and rough seas offshore certain international locations, which could limit exploration activities; and
other natural disasters.
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Any of these can result in loss of hydrocarbons, environmental pollution and other damage to our properties or the properties of
others, or restricted access to our properties.
Development drilling may not result in commercially productive quantities of crude oil and natural gas reserves from
unconventional or conventional resources.
We depend on development projects to provide sustained cash flows after investment and attractive financial returns. However,
development drilling is not always successful and the profitability of development projects may change over time.
In new development areas, available data may not allow us to completely know the extent of the reservoir or the best locations
for drilling development wells. Therefore, a development well we drill may be a dry hole or result in noncommercial quantities
of hydrocarbons.
We are planning to invest significant amounts of capital to continue development of our US onshore unconventional resources
as well as to progress the development of the Leviathan field project. In unconventional basins, development is highly
dependent on the use of new technologies to drive cost efficiencies in drilling and completion as well as on the availability of
third party infrastructure to provide flow assurance and transportation of production to end markets.
Development of offshore resources is capital and resource-intensive and may require several years to complete. In order to
timely advance significant offshore discoveries, we may progress multiple development concepts simultaneously, with the
realization that only one concept may ultimately be approved or be economically feasible. This approach may result in our
writing off costs related to certain development concepts that must be eliminated from further consideration once a final
development option has been determined.
Even if development drilling is successful and we find commercial quantities of reserves, we may encounter difficulties or
delays in completing development wells. For example, frontier areas or less developed onshore areas may not have adequate
infrastructure for gathering, processing or transportation, and production may be delayed until such infrastructure is
constructed.
Exploratory drilling, either within existing or new ventures in countries which have no history of hydrocarbon sector
investment, subjects us to risks and may not result in the discovery of commercially productive reservoirs.
Exploratory drilling requires significant capital investment and does not always result in commercial quantities of hydrocarbons
or new development projects. In addition, exploratory drilling activities may be curtailed, delayed or canceled, or development
plans may change, resulting in significant exploration expense, as a result of a variety of factors, including unexpected drilling
conditions and pressure or other irregularities in formations. Furthermore, remote locations may make it more difficult and
time-consuming to transport personnel, equipment and supplies, and we may face more difficult environments, such as oil
sands, deepwater, or ultra-deepwater in our efforts to seek new reserves, and may need to develop or invest in new
technologies. These operating environments, and potential for harsh weather, increase cost as well as drilling risk.
Exploratory dry holes can occur because seismic data and other technologies we use to determine potential exploratory drilling
locations do not allow us to know conclusively prior to drilling a well that crude oil or natural gas is present or may be
produced economically. In addition, a well may be successful in locating hydrocarbons, but we and our partners may decide not
to develop the prospect due to other considerations.
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In addition, for certain capital-intensive offshore projects, it may take several years to evaluate the future potential of an
exploratory well and make a determination of its economic viability, resulting in delays in cash flows from production start-up
and a lower return on our investment.
We hold working interests in certain areas, including offshore areas of Cyprus, Cameroon, Gabon and Newfoundland (Canada)
where there is minimal or no crude oil, natural gas or NGL production, and in certain cases, limited infrastructure. If
commercial quantities of hydrocarbons are discovered, societies with minimal or no current production must begin to address
such topics as sector regulation and distribution of government proceeds from hydrocarbon sales, the results of which could
have a negative impact on our business. We may not be able to compensate for or fully mitigate these risks. See Item 8.
Financial Statements and Supplementary Data – Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold
Costs.
Our operations require us to comply with a number of US and international laws and regulations, violations of which could
result in substantial fines or sanctions and/or impair our ability to do business.
Our operations require us to comply with complex and frequently-changing US and international laws and regulations, such as
those involving anti-corruption, competition and antitrust, anti-boycott, anti-money laundering, import-export control,
marketing, environmental and/or taxation.
For example, the US Foreign Corrupt Practices Act (FCPA) and similar laws and regulations enacted or promulgated by
countries pursuant to the 1997 Organisation for Economic Cooperation and Development Anti-Bribery Convention generally
prohibit improper payments to foreign officials for the purpose of obtaining or keeping business. We conduct some of our
operations in developing countries that have relatively underdeveloped legal and regulatory systems compared to more
developed countries. These countries generally are perceived as presenting an increased risk of corruption. Additionally, certain
of our operations involve the use of agents and other intermediaries whose conduct and actions could be imputed to us by anti-
corruption enforcement authorities. Violations of the FCPA or other anti-corruption laws could subject us to substantial fines or
sanctions and impair our ability to do business.
The import/export of equipment and supplies necessary for oil and gas exploration and development activities, as well as the
export of crude oil, natural gas, and liquids production are regulated by the import/export laws of the US and other countries in
which we operate. In the US, certain items required for oil and gas development activities may be considered “dual-use”,
having both commercial and military applications and, therefore, may be subject to specific import or export restrictions. In
addition, the US government imposes economic and trade sanctions against certain foreign countries and regimes. The
sanctions are based on US foreign policy and national security goals and may change over time.
Mergers of businesses often require the approval of certain government or regulatory agencies and such approval could contain
terms, conditions, or restrictions that would be detrimental to our business after a merger. US antitrust laws require waiting
periods and even after completion of a merger, governmental authorities could seek to block or challenge a merger as they
deem necessary or desirable in the public interest. We have merged with or acquired other companies in the past. Prevention of
a merger by antitrust laws could impair our ability to do business. Furthermore, mergers and acquisitions expose us to potential
lawsuits or other obligations not yet anticipated at time of merger or acquisition. Such liabilities and obligations could hinder
our ability to fully benefit from the acquired business or assets and negatively impact our financial performance.
As a developer, owner and operator of crude oil and natural gas properties, we are subject to various laws and regulations
relating to the discharge of materials into, and the protection of, the environment. Failure to comply with these laws and
regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site
restoration costs and liens, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that
additional pollution controls be installed and, in some instances, issuance of orders or injunctions limiting or requiring
discontinuation of certain operations. See We are subject to increasing governmental regulations and environmental
requirements that may cause us to incur substantial incremental costs, below, and Item 8. Financial Statements and
Supplementary Data – Note 17. Commitments and Contingencies.
Federal, state and local hydraulic fracturing and water disposal legislation and regulation could increase our costs or
restrict our ability to produce crude oil, natural gas and NGLs economically and in commercial quantities.
While hydraulic fracturing has been utilized in oil and gas development for decades, certain parties have called for further
study of the technique's alleged environmental and health effects, for additional regulation of the technique and, in some cases,
for a moratorium or ban on the use of hydraulic fracturing. Because of elevated public sensitivity around the topic, federal, state
and local governments are continually conducting studies, evaluating their regulatory programs and considering additional
requirements on and regulation of hydraulic fracturing practices.
At the national level, proposals have been introduced from time to time in the US Congress that, if implemented, would subject
hydraulic fracturing to further regulation, thereby limiting its use or increasing its cost.
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Federal agencies addressing hydraulic fracturing under existing authorities include the EPA, which has issued technical reports
and developed various rules and guidelines regarding hydraulic fracturing activities, and the BLM, under the US Department of
the Interior, which has issued final rules impacting hydraulic fracturing on federal and Indian lands. Some of these rules are
subject to pending challenges and, on March 28, 2017, an executive order was signed directing the EPA and the BLM to review
their rules and, if appropriate, to initiate rulemaking to rescind or revise them consistent with the stated policy of promoting
clean and safe development of the nation’s energy resources, while at the same time avoiding regulatory burdens that
unnecessarily encumber energy production. Accordingly, the EPA and the BLM have taken actions to delay or rescind certain
requirements related to hydraulic fracturing activities. See Items 1. and 2. Business and Properties - Hydraulic Fracturing.
Each of the states, as well as certain localities, where we operate have adopted or may adopt regulations on drilling activities in
general or hydraulic fracturing in particular that could restrict or prohibit hydraulic fracturing in certain circumstances, impose
more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. For example,
a number of local communities in Colorado have attempted to increase regulatory requirements on crude oil and natural gas
development. In addition, some state regulatory agencies have modified their regulations to account for potential
induced seismicity with regard to the operation of injection wells used for waste disposal.
We are dependent on the use of hydraulic fracturing practices to produce commercial quantities of crude oil and natural gas,
particularly from wells in our US onshore basins. Additional federal, state or local restrictions on hydraulic fracturing, water
disposal or other drilling activities that may be imposed in areas where we conduct business, such as US onshore, could
significantly increase our operating, capital and compliance costs as well as delay or halt our ability to develop crude oil,
natural gas and NGL reserves. See Items 1. and 2. Business and Properties – Regulations and – Hydraulic Fracturing.
The marketability of our production is dependent upon transportation and processing facilities over which we may have no
direct control.
The marketability of our production from our US onshore areas and Gulf of Mexico depends in part upon the availability,
proximity and capacity of pipelines, natural gas gathering systems, rail service, and processing facilities. We deliver crude oil,
natural gas and NGLs produced from these areas through gathering systems and pipelines, the majority of which we do not
own.
In Israel, we rely on a state-owned pipeline and transportation system to deliver our production to customers and end users.
Offshore Equatorial Guinea, our natural gas production is delivered to onshore processing and storage facilities operated by our
partner, and the resulting products, as well as our crude oil production from Aseng and Alen, are lifted to tankers owned by
third-parties.
Third-party systems and facilities may not be available to us in the future at a price that is acceptable to us. In addition, the lack
of availability of, or capacity on, third-party systems and facilities could reduce the price offered for our production or result in
the shut-in of producing wells or the delay or discontinuance of development plans for properties. Even where we have some
contractual control over the transportation of our production through firm transportation arrangements, third-party systems and
facilities may be temporarily unavailable due to market conditions or mechanical reliability or other reasons, including adverse
weather conditions.
Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, as well as any
delays in constructing new infrastructure systems and facilities, could delay or curtail production, thereby harming our business
and, in turn, our results of operations, cash flows, and financial condition.
Our ability to produce crude oil, natural gas and NGLs economically and in commercial quantities could be impaired if we
are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of or recycle the water
we use economically and in an environmentally safe manner.
Drilling and development activities require the use of water and results in the production of waste water. For example, the
hydraulic fracturing process, which we employ to produce commercial quantities of crude oil, natural gas and NGLs from
many reservoirs, requires the use and disposal of significant quantities of water. In certain regions, there may be insufficient
local capacity to provide a source of water for drilling activities. In those cases, water must be obtained from other sources and
transported to the drilling site, adding to the development cost. Waste water from oil and gas operations often is disposed of via
underground injection. Some studies have linked earthquakes or induced seismicity in certain areas to underground injection,
which is leading to increased public scrutiny of injection safety.
The development of new environmental initiatives or regulations related to acquisition, withdrawal, storage and use of surface
water or groundwater, or treatment and discharge of water waste, may limit our ability to use techniques such as hydraulic
fracturing, increase our development and operating costs and cause delays, interruptions or termination of our operations, the
extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial condition. See
Items 1. and 2. Business and Properties – Hydraulic Fracturing.
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Failure to adequately fund continued capital expenditures could adversely affect our properties.
Our exploration, development, and acquisition activities require capital expenditures to achieve production and cash flows. In
particular, major offshore projects have a multi-year long development cycle time, which means that development spending
occurs for several years before the project begins producing hydrocarbons and generating cash flows. As examples, assets and
infrastructure for export of natural gas from Leviathan require a multi-billion dollar investment prior to production startup.
Furthermore, while the majority of our assets are held by production, certain of our assets, such as our Eagle Ford Shale and
Delaware Basin properties, are held through continuous development obligations. Therefore, we are contractually obligated to
fund a level of development activity in these areas and failure to meet these obligations may result in the loss of a lease.
Historically, we have funded our capital expenditures through a combination of cash flows from operations, our unsecured
revolving credit facility (Revolving Credit Facility), debt and equity issuances, and occasional sales of assets. Future cash flows
from operations are subject to a number of variables, such as the level of production from existing wells, commodity prices,
and our success in finding, developing and producing new reserves.
For 2018, our capital investment program is flexible to address potential commodity price changes. If commodity prices decline
for an extended period of time, we will evaluate our level of capital spending and likely reduce our investment program. As a
result, we will have less ability to replace our reserves through drilling operations and may elect to forfeit our ownership
interests or rights to participate in some properties, resulting in lower production over time as compared with prior years. See
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Operating Outlook – 2018
Capital Investment Program.
A negative shift in investor sentiment of the oil and gas industry could adversely affect our ability to raise equity
and debt capital.
Certain segments of the investor community have recently developed negative sentiment towards investing in our
industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and gas
representation in certain key equity market indices. Some investors, including certain pension funds, university
endowments and family foundations, have stated policies to disinvest in the oil and gas sector based on their social
and environment considerations. Certain other stakeholders have also pressured commercial and investment banks
to stop funding oil and gas projects.
Such developments could result in downward pressure on the stock prices of oil and gas companies, including ours.
This may also potentially result in a reduction of available capital funding for potential development projects
impacting our future financial results.
Indebtedness may limit our liquidity and financial flexibility.
At December 31, 2017, we had $6.8 billion of consolidated debt, and indebtedness represented 39% of our total book
capitalization (sum of debt plus shareholders' equity).
Our indebtedness affects our operations in several ways, including the following:
•
a portion of our cash flows from operating activities must be used to service our indebtedness and is not available for
other purposes;
• we may be at a competitive disadvantage as compared to similar companies that have less debt;
•
a covenant contained in our Credit Agreement provides that our total debt to capitalization ratio (as defined in the
Credit Agreement) will not exceed 65% at any time, which may make additional borrowings more expensive, thereby
affecting our flexibility in planning for, and reacting to, changes in the economy and our industry;
additional future financing for working capital, capital expenditures, acquisitions, general corporate or other purposes
may have higher costs and more restrictive covenants;
changes in our debt credit ratings may negatively affect the cost, terms, conditions and/or availability of future
financing, and lower ratings will increase the interest rate and fees we pay on our Revolving Credit Facility; and
•
•
• we may be more vulnerable to general adverse economic and industry conditions.
We may incur additional debt in order to fund our exploration, development and acquisition activities. A higher level of
indebtedness increases the risk that our financial flexibility may deteriorate. Our ability to meet our debt obligations and service
our debt depends on future performance. General economic conditions, commodity prices, and financial, business and other
factors will affect our operations and our future performance. Many of these factors are beyond our control and we may not be
able to generate sufficient cash flow to pay the interest on our debt, and future working capital, borrowings and equity
financing may not be available to pay or refinance such debt. See Item 8. Financial Statements and Supplementary Data – Note
10. Long-Term Debt.
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A downgrade or other negative action with respect to our credit rating could negatively impact our business and financial
condition.
A downgrade or other negative rating action could affect our requirements to post collateral as financial assurance of
performance under certain contractual arrangements, such as pipeline transportation contracts, crude oil and natural gas sales
contracts, work commitments and certain abandonment obligations, and potentially subject us to additional bonding and other
assurance requirements with respect to our Gulf of Mexico assets. A lowering of our credit rating may negatively affect the
cost, terms, conditions and availability of future financing.
We face significant competition and many of our competitors have resources in excess of our available resources.
We operate in highly competitive areas of crude oil and natural gas exploration, development, acquisition and production. We
face intense competition from:
large multi-national, integrated oil and gas companies;
•
•
state-controlled national oil companies;
• US independent oil and gas companies;
• US onshore midstream companies;
•
•
service companies engaging in exploration and production activities; and
private investing in oil and gas equity funds.
We face competition in a number of areas such as:
seeking to acquire desirable producing properties or new leases for future exploration;
acquiring or increasing access to gathering, processing and transportation services and capacity;
•
•
• marketing our crude oil, natural gas and NGL production;
•
•
seeking to acquire the equipment and expertise necessary to operate and develop properties; and
attracting and retaining employees with certain skills.
Many of our competitors have financial and other resources substantially in excess of those available to us. Such companies
may be able to pay more for seismic information and lease rights on crude oil and natural gas properties and exploratory
prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or
human resources permit. This highly competitive environment could have an adverse impact on our business.
Estimates of crude oil, natural gas and NGL reserves are not precise.
Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, natural gas and NGLs that
cannot be measured in an exact manner, and there are numerous uncertainties inherent in estimating reserves quantities and
their value, including factors that are beyond our control.
In accordance with the SEC's rules for oil and gas reserves reporting, our reserves estimates are based on 12-month average
commodity prices; therefore, reserves quantities will change when actual prices increase or decrease. As estimated production,
development and abandonment costs are based on year-end economic conditions, reserves quantities will also change when
these costs increase or decrease.
Reserves estimates depend on a number of factors and assumptions that may vary considerably from actual results, including:
historical production from the area compared with production from other areas;
the assumed effects of regulations by governmental agencies, including the SEC;
assumptions concerning future crude oil, natural gas, and NGL prices;
anticipated development cycle time;
future development costs;
future operating and abandonment costs;
impacts of cost recovery provisions in contracts with foreign governments;
severance and excise taxes; and
•
•
•
•
•
•
•
•
• workover and remedial costs.
For these reasons, estimates of the economically recoverable quantities of crude oil, natural gas and NGLs attributable to any
particular group of properties, classifications of those reserves based on risk of recovery, and estimates of the future net cash
flows expected from them prepared by different petroleum engineers, or by the same petroleum engineers but at different times,
may vary substantially. Estimation of crude oil, natural gas and NGL reserves in emerging areas or areas with limited historical
production is inherently more difficult, and we may have less experience in such areas. Accordingly, reserves estimates may be
subject to positive or negative revisions, and actual production, revenues and expenditures with respect to our reserves likely
will vary, possibly materially, from estimates. Any such negative revisions could result in an asset impairment charge.
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Additionally, some of our reserves estimates are calculated using volumetric analysis, which involves estimating the volume of
a reservoir based on the net feet of pay of the structure and an estimation of the area covered by the structure. Reserves
estimates using volumetric analysis are less reliable than estimates based on a lengthy production history.
In addition, realization or recognition of PUDs will depend on our development schedule and plans. A change in future
development plans for PUDs could cause the discontinuation of the classification of these reserves as proved. See Items 1. and
2. Business and Properties – Proved Reserves Disclosures.
We operate in a litigious environment.
Some of the jurisdictions within which we operate have proven to be litigious environments. Oil and gas companies, such as us,
can be involved in various legal proceedings, such as title, royalty, or contractual disputes, in the ordinary course of business.
For example, in certain states, oil and gas companies are often the target of “legacy lawsuits,” by which a landowner claims that
oil and gas operations, often performed many years ago and by another operator, caused pollution or contamination of a
property. Various properties we have owned over the past decades potentially expose us to “legacy lawsuit” claims. Similarly,
neighboring landowners may allege that current operations cause contamination or create a nuisance.
Because we maintain a diversified portfolio of assets that includes both US and international projects, the complexity and types
of legal procedures with which we may become involved may vary, and we could incur significant legal and support expenses
in different jurisdictions. For instance, we historically have had to address certain fiscal, antitrust and other regulatory
challenges in Israel, including a current class action lawsuit filed by petitioners alleging we and our partners in Tamar violated
antitrust laws through the monopolistic pricing of natural gas to the citizens of Israel. Legal proceedings such as this could
result in a substantial liability and/or negative publicity about us and adversely affect the price of our common stock. In
addition, legal proceedings distract management and other personnel from their primary responsibilities. These proceedings are
subject to the uncertainties inherent in any litigation. We will defend ourselves vigorously in all such matters. However, if we
are not able to successfully defend ourselves, there could be a delay or even halt in our exploration, development or production
activities or other business plans, resulting in a reduction in reserves, loss of production and reduced cash flows.
One of our subsidiaries acts as the general partner of a publicly traded master limited partnership, Noble Midstream
Partners, which may involve a greater exposure to legal liability than our historic business operations.
One of our subsidiaries acts as the general partner of Noble Midstream Partners, a publicly traded master limited partnership.
Our control of the general partner of Noble Midstream Partners may increase the possibility that we could be subject to claims
of breach of fiduciary duties, including claims of conflicts of interest, related to Noble Midstream Partners. Any liability
resulting from such claims could have a material adverse effect on our future business, financial condition, results of operations
and cash flows.
We may be subject to risks in connection with acquisition and divestiture activities.
As part of our business strategy, we have made, and will likely continue to make, acquisitions of oil and gas properties and/or
entities that own them. Furthermore, if we are unable to make attractive acquisitions, our future growth could be limited.
Moreover, even if we do make acquisitions, they may not result in an increase in our cash flows from operations or otherwise
result in the benefits anticipated due to various risks, including, but not limited to:
•
•
•
•
•
incorrect estimates or assumptions about reserves, exploration potential or potential drilling locations;
incorrect assumptions regarding future revenues, including future commodity prices and differentials, or regarding
future development and operating costs;
incorrect assumptions regarding potential synergies and the overall costs of equity or debt;
difficulties in integrating the operations, technologies, products and personnel of the acquired assets or business; and
unknown and unforeseen liabilities or other issues related to any acquisition for which contractual protections prove
inadequate, including environmental liabilities and title defects.
The acquisition of a property or business requires management to make complex judgments and assessments, and the accuracy
of the assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties
that we believe to be consistent with industry practices. Our review will not reveal all existing or potential problems, nor will it
permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities.
We also maintain an ongoing portfolio management program to ensure our company is well-positioned with assets that offer
growth at financially attractive investment options. Therefore, we may periodically divest certain material assets which may
help to generate organizational and operational efficiencies as well as cash for use in our capital investment program or to repay
outstanding debt.
We strive to obtain the most attractive prices for our assets; however, various factors can materially affect our ability to dispose
of assets on terms acceptable to us. Such factors may include:
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current commodity prices;
laws and regulations impacting oil and gas operations in the areas where the assets are located;
•
•
• willingness of the purchaser to assume certain liabilities such as asset retirement obligations;
•
•
our willingness to indemnify buyers for certain matters; and
delays in closing.
Inability to achieve a desired price for the assets, or underestimation of amounts of retained liabilities or indemnification
obligations, can result in a reduction of cash proceeds, a loss on sale due to an excess of the asset's net book value over
proceeds, or liabilities which must be settled in the future at amounts that are higher than we anticipated. In addition, although
we may successfully divest oil and gas assets, we may retain certain related contracts. For example, although we sold our
Marcellus Shale upstream properties in 2017, we retained significant obligations under firm transportation contracts. Our
inability to fully commercialize these contracts and reduce the associated financial commitments could result in a decrease in
cash flows from operations. In addition, we may be required to recognize losses in accordance with exit or disposal activities.
See Item 7. Management's Discussion of Financial Condition and Results of Operations – Liquidity and Capital Resources –
Contractual Obligations.
An uneconomic or unsuccessful acquisition or divestiture effort may divert management’s attention and our financial resources
away from existing operations, which could have a material adverse effect on our financial condition and results of operations.
We are exposed to counterparty credit risk as a result of our receivables, hedging transactions and cash investments.
We are exposed to risk of financial loss from joint venture and other receivables. We are the operator on a majority of our joint
venture development projects, including Leviathan. As operator of the joint ventures, we pay joint venture expenses and make
cash calls on our nonoperating partners for their respective shares of joint venture costs. These projects are capital cost
intensive and, in some cases, a nonoperating partner may experience a delay in obtaining financing for its share of the joint
venture costs or have liquidity problems resulting in slow payment of joint venture costs that can result in potential delays in
our development projects.
In addition, some of our joint venture partners are not as creditworthy as we are and may experience credit rating downgrades
or liquidity problems that may hinder their ability to obtain financing. Counterparty liquidity problems could result in a delay in
our receiving proceeds from reimbursement of joint venture costs. Nonperformance by a joint venture partner could result in
significant financial losses.
Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract.
During periods of falling commodity prices, our commodity derivative receivable positions increase, which increases our
counterparty credit exposure. We also had approximately $675 million in cash and cash equivalents at December 31, 2017
deposited with financial institutions, a majority of which was invested in money market funds and short-term deposits with
major financial institutions. While we monitor the creditworthiness of the banks and financial institutions with which we invest
and engage in hedging transactions, and maintain credit insurance, we are unable to predict sudden changes in solvency of the
financial institutions and may be exposed to associated risks.
If one or more of our joint venture partners, hedge counterparties and financial institutions were to experience a sudden
deterioration in liquidity, it could impair their ability to perform under the terms of our contracts. We are unable to predict
sudden changes in creditworthiness or ability of these parties to perform and could incur significant financial losses.
Credit enhancements have been obtained from some parties in the form of parental guarantees, letters of credit or credit
insurance; however, not all of our counterparty credit is protected through guarantees or credit support. In addition, we maintain
credit insurance associated with specific purchasers. However, nonperformance by a hedge counterparty or financial institution
could result in significant financial losses.
Commodity hedging transactions may limit our potential gains or fail to protect us from declines in commodity prices.
In order to reduce the impact of commodity price uncertainty and increase cash flow predictability relating to the marketing of
our crude oil and natural gas, we enter into hedging arrangements with respect to a portion of our expected revenues. Our
hedges, consisting of a series of derivative instrument contracts, are limited in duration, usually for periods of one to three
years. While intended to reduce the effects of volatile crude oil and natural gas prices, such transactions may limit our potential
gains if prices rise over the price established by the arrangements. Conversely, our hedging program may be inadequate to
protect us from continuing and prolonged declines in the price of crude oil or natural gas.
Global commodity prices are volatile. Such volatility challenges our ability to forecast and, as a result, it may become more
difficult to manage our hedging program. In trying to manage our exposure to commodity price risk, we may end up hedging
too much or too little, depending upon how our crude oil or natural gas volumes and our production mix fluctuate in the future.
Hedging transactions may also expose us to the risk of financial loss in certain circumstances, including instances in which: our
production is less than expected; there is a widening of price basis differentials between delivery points for our production and
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the delivery points assumed in the hedge arrangement; the counterparties to our futures contracts fail to perform under the
contracts; or a sudden unexpected event materially impacts crude oil or natural gas prices. See Item 8. Financial Statements
and Supplementary Data – Note 8. Derivative Instruments and Hedging Activities.
The insurance we carry is insufficient to cover all of the risks we face, which could result in significant financial exposure.
Exploration for and production of crude oil and natural gas can be hazardous, involving natural disasters or other catastrophic
events such as hurricanes, earthquakes, blowouts, well cratering, fire and explosion, loss of well control, pipeline disruptions,
mishandling of fluids and chemicals, and possible underground migration of hydrocarbons and chemicals, any of which can
result in damage to or destruction of wells or formations or production facilities, injury to persons, loss of life, or damage to
property and the environment. Exploration and production activities are also subject to risk from political developments such as
terrorist acts, piracy, civil disturbances, war, and expropriation or nationalization of assets, or other interruptions, such as cyber
security breaches, which can cause loss of or damage to our property.
Our insurance program and memberships in domestic and international dedicated oil spill and emergency response
organizations may not minimize or fully protect us from losses resulting from damages to or the loss of physical assets or loss
of human life, liability claims of third parties, and business interruption (loss of production) attributed to certain assets and
including such occurrences as well blowouts and resulting oil spills. We do not have insurance protection against all the risks
we face, because we choose not to insure certain risks, insurance is not available at a level that balances the cost of insurance
and our desired rates of return, or actual losses may exceed coverage limits.
We expect the future availability and cost of insurance to be impacted by such events as hurricanes, earthquakes, tsunami and
other natural disasters. Impacts could include tighter underwriting standards; limitations on scope and amount of coverage; and
higher premiums, and will depend, in part, on future changes in laws and regulations regarding exploration and production
activities in the Gulf of Mexico and other areas in which we operate, including possible increases in liability caps for claims of
damages from oil spills. We will continue to monitor for any legislative or regulatory changes related to offshore exploration
and production and its potential impact on the insurance market and our overall risk profile, and adjust our risk and insurance
program to provide protection, at a level that we can afford considering the cost of insurance and our desired rates of return,
against disruption to our operations and cash flows.
If an event, for example, a major offshore incident resulting in significant personal injury and/or environmental and physical
damage, occurs that is not covered by insurance or not fully protected by insured limits, it could have a significant adverse
impact on our financial condition, results of operations and cash flows. See Risk and Insurance Program, above.
Provisions in our Certificate of Incorporation and Delaware law may inhibit a takeover of us.
Under our Certificate of Incorporation, our Board of Directors is authorized to issue shares of our common or preferred stock
without approval of our shareholders. Issuance of these shares could make it more difficult to acquire us without the approval
of our Board of Directors as more shares would have to be acquired to gain control. In addition, Delaware law imposes
restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding
common stock. These provisions may deter hostile takeover attempts that could result in an acquisition of us that would have
been financially beneficial to our shareholders.
Item1B. Unresolved Staff Comments
None.
Item 3. Legal Proceedings
We are involved in various legal proceedings in the ordinary course of business. These proceedings are subject to the
uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters and we believe that the
ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations
or cash flows. For discussion of material legal proceedings, see Item 8. Financial Statements and Supplementary Data – Note
17. Commitments and Contingencies.
Item 4. Mine Safety Disclosures
Not Applicable.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
Common Stock Our common stock, $0.01 par value, is listed and traded on the NYSE under the symbol “NBL.” The
declaration and payment of dividends will be determined on a quarterly basis and are at the discretion of our Board of Directors
PART II
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and the amount thereof will depend on our results of operations, financial condition, contractual restrictions, cash requirements,
future prospects and other factors deemed relevant by the Board of Directors.
Stock Prices and Dividends by Quarters The high and low sales price per share of our common stock on the NYSE and
quarterly dividends paid per share were as follows:
High
Low
Dividends Per Share
$
$
2016
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
2017
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
$
$
35.04
38.62
37.50
42.03
40.89
35.74
30.06
29.58
$
$
23.77
29.47
32.71
33.75
32.33
27.66
22.99
22.99
0.10
0.10
0.10
0.10
0.10
0.10
0.10
0.10
On January 30, 2018, our Board of Directors declared a quarterly cash dividend of $0.10 per common share. The dividend will
be paid February 26, 2018, to shareholders of record on February 12, 2018. The amount of future dividends will be determined
on a quarterly basis at the discretion of our Board of Directors and will depend on earnings, financial condition, capital
requirements and other factors.
Transfer Agent and Registrar The transfer agent and registrar for our common stock is Wells Fargo Bank, N.A., 1110 Centre
Pointe Curve, Suite 101 Mendota Heights, MN 55120.
Stockholders’ Profile Pursuant to the records of the transfer agent, as of February 9, 2018, the number of holders of record of
our common stock was 561.
Stock Repurchases The following table summarizes repurchases of our common stock occurring in fourth quarter 2017:
Period
10/1/2017 - 10/31/2017
11/1/2017 - 11/30/2017
12/1/2017 - 12/31/2017
Total
Total Number
of
Shares
Purchased (1)
Average
Price Paid
Per Share
Total Number of
Shares Purchased
as Part of Publicly
Announced Plans or
Programs
Approximate Dollar
Value of Shares that
May Yet Be
Purchased Under the
Plans or Programs
(in thousands)
390
$
85
20,173
20,648
$
28.33
28.30
25.68
25.74
—
—
—
—
—
—
—
—
(1) Stock repurchases during the period related to stock received by us from employees for the payment of withholding taxes due on shares
of restricted stock issued under our stock-based compensation plans.
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Stock Performance Graph This graph shows our cumulative total shareholder return over the five-year period from December
31, 2012 to December 31, 2017. The graph also shows the cumulative total returns for the same five-year period of the S&P
500 Index and a peer group of companies. The cumulative total return of the common stock of our peer group of companies
includes the cumulative total return of our common stock.
Our peer group includes a broad group of US onshore and global exploration and production companies which are further
diversified by location and number of resource plays as well as level of integration within the crude oil and natural gas business
cycle. Our peer group consists of the following:
Anadarko Petroleum Corp.
Apache Corp.
Cabot Oil & Gas Corp.
Chesapeake Energy Corp.
Continental Resources, Inc.
Devon Energy Corp.
EOG Resources, Inc.
Hess Corp.
Marathon Oil Corp.
Murphy Oil Corp.
Noble Energy, Inc.
Pioneer Natural Resources Co.
Range Resources Corp.
Southwestern Energy Co.
The comparison assumes $100 was invested on December 31, 2012 in our common stock, in the S&P 500 Index and in our peer
group of companies and assumes that all of the dividends were reinvested. In addition, the peer group investment is weighted
based upon the market capitalization of each individual company within the peer group.
Year Ended December 31,
Noble Energy, Inc.
S&P 500
Peer Group
2013
2014
2015
2016
2017
$
135.07 $
132.39
131.72
95.06 $
150.51
113.35
67.16 $
152.59
70.13
78.54 $
170.84
101.33
60.93
208.14
90.55
Equity Compensation Plan Information The information required by this item is incorporated herein by reference to the 2018
Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2017.
52
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Index to Financial Statements
Item 6. Selected Financial Data
(millions, except as noted)
Revenues and Income
Total Revenues
(Loss) Income from Continuing Operations Including
Noncontrolling Interests
Net (Loss) Income Including Noncontrolling
Net (Loss) Income Attributable to Noble Energy
Per Share Data, Attributable to Noble Energy
(Loss) Earnings Per Share - Basic
(Loss) Income from Continuing Operations
(Loss) Earnings Per Share - Basic
(Loss) Earnings Per Share - Diluted
(Loss) Income from Continuing Operations
(Loss) Earnings Per Share - Diluted
Cash Dividends Per Share
Year-End Stock Price Per Share
Weighted Average Shares Outstanding
Basic
Diluted
Cash Flows
Net Cash Provided by Operating Activities
Additions to Property, Plant and Equipment
Proceeds from Divestitures (1)
Proceeds from Issuance of Noble Energy Common
Stock, Net of Offering Costs
Proceeds from Issuance of Noble Midstream Partners
Common Units, Net of Offering Costs
Financial Position
Cash and Cash Equivalents
Property, Plant, and Equipment, Net
Goodwill (2)
Total Assets
Long-term Obligations
2017
Year Ended December 31,
2015
2014
2016
2013
$
4,256
$
3,491
$
3,183
$
5,115
$
5,015
(1,050)
(1,050)
(1,118)
(985)
(985)
(998)
(2,441)
(2,441)
(2,441)
1,214
1,214
1,214
$
(2.38) $
(2.38)
(2.32) $
(2.32)
(6.07) $
(6.07)
$
3.36
3.36
(2.38)
(2.38)
0.40
29.14
469
469
1,951
2,649
2,073
—
312
675
17,502
1,310
21,476
$
$
(2.32)
(2.32)
0.40
38.06
430
430
1,351
1,541
1,241
—
299
1,180
18,548
—
21,011
$
$
(6.07)
(6.07)
0.72
32.93
402
402
2,062
2,979
151
1,112
—
1,028
21,300
—
24,196
$
$
3.27
3.27
0.68
47.43
361
367
3,506
4,871
321
—
—
1,183
18,143
620
22,518
$
$
$
$
907
978
978
2.53
2.72
2.50
2.69
0.55
68.11
359
363
2,937
3,947
327
—
—
1,117
15,725
627
19,642
Long-Term Debt
Deferred Income Taxes
Asset Retirement Obligations, Noncurrent
Other
4,566
2,441
547
562
Total Equity
9,184
(1) Proceeds for 2017 relate to the Marcellus Shale upstream divestiture and proceeds received from other transactions. Proceeds for 2016
primarily relate to US onshore non-strategic asset divestiture activity and the sell-down of Tamar interest. See Item 8. Financial
Statements and Supplementary Data – Note 4. Acquisitions, Divestitures and Merger
6,068
2,516
670
417
10,325
7,976
2,826
861
358
10,370
6,746
1,127
824
421
10,619
7,011
1,819
775
328
9,600
(2) Goodwill at December 31, 2017 related to the Clayton Williams Energy Acquisition. Our previous goodwill balance was fully impaired
at December 31, 2015. See Item 8. Financial Statements and Supplementary Data – Note 1. Summary of Significant Accounting
Policies.
53
Year Ended December 31,
2015
2014
2016
$
$
$
125
40.39
54
14.92
1,397
2.42
333
219
5,308
1,437
2,274
$
$
$
112
45.00
39
13.91
1,187
2.44
307
189
5,549
1,421
2,395
103
91.58
23
33.75
992
3.38
304
128
5,833
1,404
2,735
$
$
$
2013
99
100.29
16
35.53
901
2.97
322
113
5,828
1,406
2,527
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Index to Financial Statements
Operations Information - Consolidated Operations
Consolidated Crude Oil Sales (MBbl/d)
Average Realized Price ($/Bbl)
Consolidated NGL Sales (MBbl/d)
Average Realized Price ($/Bbl)
Consolidated Natural Gas Sales (MMcf/d)
Average Realized Price ($/Mcf)
Proved Reserves
Crude Oil and Condensate Reserves (MMBbls)
NGL Reserves (MMBbls)
Natural Gas Reserves (Bcf)
Total Reserves (MMBoe)
Number of Employees
$
$
$
2017
$
$
$
129
49.73
58
23.40
1,118
3.01
457
229
7,680
1,965
2,277
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Index to Financial Statements
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
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 our management. Our MD&A is presented in the following major sections:
• Executive Summary;
• Executive Overview;
• Operating Outlook;
• Results of Operations - E&P;
• Results of Operations - Midstream;
• Results of Operations - Corporate;
• Liquidity and Capital Resources; and
• Critical Accounting Policies and Estimates.
The accompanying consolidated financial statements, including the notes thereto, contain detailed information that should be
read in conjunction with our MD&A.
EXECUTIVE SUMMARY
Noble Energy Key Metrics (see links below for further information)
Items 1. and 2. Business and Properties – Sales Volume,
Price and Cost Data
Results of Operations - E&P
Items 1. and 2. Business and Properties – Proved Reserves
Disclosures
Item 8. Financial Statements and Supplementary Data –
Supplementary Oil and Gas Information (Unaudited)
55
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Liquidity and Capital Resources – Cash Flows
Item 8. Financial Statements and Supplementary Data –
Consolidated Statements of Cash Flows
Items 1. and 2. Business and Properties – Domestic and
International
Liquidity and Capital Resources – Acquisition, Capital
Expenditures and Other Exploration Expenditures
Items 1. and 2. Business and Properties – Sales Volume, Price
and Cost Data
Results of Operations - E&P
Items 1. and 2. Business and Properties – Proved
Reserves Disclosures
Item 8. Financial Statements and Supplementary Data –
Supplemental Oil and Gas Information (Unaudited)
56
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EXECUTIVE OVERVIEW
Industry Outlook
Crude Oil The global oil and gas industry is cyclical, and crude oil prices are volatile, driven by crude oil supply, which
includes OPEC and non-OPEC producers, and global crude oil demand.
In 2014, our industry entered a downturn due to oversupplied crude oil production from non-OPEC producers, primarily driven
by US unconventional oil production growth from tight formations and the de-bottlenecking of transportation infrastructure.
Coupled with OPEC’s decision not to reduce production quotas and muted global crude oil demand growth, crude oil prices
began falling rapidly in late 2014.
The rapid decline in crude oil prices impacted US and other non-OPEC producers' capital budgets, which resulted in lower
crude oil production. Further, in late 2016, OPEC announced voluntary production curtailments in an effort to stabilize excess
crude oil supply and crude oil prices and to rebalance crude oil inventories. The decline in supply from these producers has
aided in stabilizing the crude oil market. As a result, crude oil prices have recently recovered to three-year record highs, while
production from the US has increased, allowing US producers to absorb global market share.
Global crude oil products demand has increased, supported by lower crude oil prices and a synchronized global economic
recovery, leading to increased refinery utilization and crude oil demand. Increased demand has further contributed to stabilizing
crude oil prices.
The outlook for 2018 crude oil prices will continue to depend on supply and demand dynamics, as well as global geopolitical
and security factors in crude oil-producing nations. Reductions in industry investment, particularly for conventional crude oil
development, will, over time, contribute to production declines, helping to balance supply and demand in the crude oil market.
Natural Gas The US domestic natural gas market remains oversupplied as domestic production has continued to grow due to
drilling efficiencies, completion of DUC well inventory and de-bottlenecking of transportation infrastructure. In contrast to
crude oil supply curtailments, there has been little to offset natural gas supply growth, which continues to outpace demand
domestically. As a result, natural gas prices remained range-bound in 2017. We expect this situation to continue into 2018, with
natural gas prices at or near current or recent trading levels.
Impact of Current Commodity Prices Modest commodity price improvement has increased both our consolidated average
realized crude oil and consolidated average natural gas prices by approximately 20% in 2017 as compared to 2016. The chart
below shows the historical trend in benchmark prices for West Texas Intermediate (WTI) crude oil, Brent crude oil and US
Henry Hub natural gas.
Because the global economic outlook and commodity price environment are uncertain, we have maintained a robust financial
liquidity position to ensure financial flexibility. We have also planned a 2018 capital investment program that will be flexible
and responsive to positive or negative price conditions that may develop and support continued business investment in a
volatile commodity price environment. See 2018 Capital Investment Program, below.
See Item 1A. Risk Factors – The oil and gas industry is cyclical and an extended period of suppressed commodity prices could
have material adverse effects on our operations, our liquidity, and the price of our common stock.
Development and Operating Costs Third party oilfield service and supply costs are also subject to supply and demand
dynamics. During 2017, increases in US onshore drilling and completion activity resulted in higher demand for oilfield
services. As a result, the costs of drilling, equipping and operating wells and infrastructure experienced some inflation, which,
57
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along with commodity prices, impacted industry operating margins. Conversely, the industry has reduced capital-intensive
offshore exploration and drilling activities in response to the commodity price environment. Demand for and costs associated
with offshore conventional oil services have declined and, in the near-term, will likely not be subject to cost inflation.
Recent Activities Implementation of our focused strategy has enhanced our future outlook. Over the past three years, we
have made significant changes and enhancements to our business:
Portfolio Transformation, Including:
•
•
•
•
•
entered the liquids-rich Eagle Ford Shale and Delaware Basin through the Rosetta Merger;
expanded our Delaware Basin position through the Clayton Williams Energy Acquisition;
exited the Marcellus Shale upstream and are exiting the Marcellus Shale midstream, thereby accelerating monetization
of assets not attracting capital;
established the Noble Midstream business, including an initial public offering of Noble Midstream Partners, and
executed the first asset drop down transaction; and
accelerated DJ Basin value through numerous acreage exchanges and sales.
Operational Accomplishments, Including:
•
•
•
•
•
focused capital and resources on highest-margin assets within US onshore liquids plays and the Eastern
Mediterranean;
sanctioned the initial phase of Leviathan development, with first natural gas sales targeted for the end of 2019;
excluding the impact of the Marcellus Shale upstream divestiture, increased proved reserves by more than 65% from
2016;
excluding the impact of the Marcellus Shale upstream divestiture, increased total US onshore sales volumes by more
than 15% from 2016 and shifted to an oilier production mix, with more than 40% of our US onshore consolidated
sales volumes attributable to crude oil; and
improved well level and corporate returns with technology advancements and structural cost savings.
Financial Strength, Including:
proactive and strategic action to manage within cash flows;
•
• made net repayments of debt totaling $1.69 billion, since beginning of 2016 through cash on hand, proceeds from
asset sales, and cash generated by our midstream business;
• maintained a strong liquidity position including cash on hand and unused borrowing capacity; and
• maintained our investment grade credit ratings.
In summary, during 2017, we closed several strategic portfolio transactions demonstrating our continued focus on enhancing
company margins and returns. Our current portfolio includes assets which are well-positioned on the industry cost of supply
curve, offering growth at financially attractive rates of return. Operationally, we continued to drive efficiencies in our US
onshore drilling and completions, while advancing our Eastern Mediterranean regional natural gas developments. Financially,
we continued to maintain our strong balance sheet and robust liquidity position.
Subsequent Events The Company has evaluated the period after the balance sheet date, noting no subsequent events or
transactions that required recognition or disclosure in the financial statements, other than as previously disclosed or noted
below.
Share Repurchase Program On February 15, 2018, we announced the Company's Board of Directors authorized a share
repurchase program of $750 million which expires December 31, 2020. All purchases will be made in accordance with
applicable securities laws from time to time in open market or private transactions, depending on market conditions, and may
be discontinued at any time.
Gulf of Mexico Divestiture On February 15, 2018, we announced the Company signed a definitive agreement to sell its assets
in the Gulf of Mexico for cash consideration of $480 million. As part of the transaction, the buyer will assume all abandonment
obligations associated with the properties which we estimate to approximate $230 million as of December 31, 2017. The net
book value of the Gulf of Mexico assets as of December 31, 2017 was approximately $750 million. We expect to incur a charge
in early 2018, subject to customary closing adjustments. The transaction is expected to close during second quarter 2018,
contingent upon the buyer’s successful implementation of its contemplated restructuring, and will be effective as of January 1,
2018.
GSPAs - Israel Export On February 19, 2018, we executed two independent GSPAs for the sale of natural gas from the
Leviathan and Tamar fields to Dolphinus Holdings Limited to supply natural gas in Egypt. Sales volumes under the GSPA
associated with the Leviathan field are anticipated to begin at a firm rate of approximately 350 MMcf/d, gross, (approximately
139 MMcf/d, net) at the startup of the Leviathan project currently anticipated at the end of 2019. For the Tamar agreement,
sales volumes are anticipated to begin at an interruptible rate of up to 350 MMcf/d, gross, (approximately 114 MMcf/d, net)
58
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dependent upon gas availability beyond existing customer obligations in Israel and Jordan. The GSPA includes an option to
convert the Tamar interruptible quantity to a firm-basis with a take or pay commitment. Both contracts are for a 10-year term
and have pricing terms indexed to Brent crude, similar to other export contracts in the region. The GSPAs are subject to
satisfaction of conditions precedent, including regulatory approvals and licenses, and finalizing gas transportation agreements.
OPERATING OUTLOOK
Growing Long-Term Value We believe the following guiding principles will contribute to growing long-term value:
• Execution of a disciplined capital allocation process by:
designing a flexible investment program aligned with the current commodity price environment; and
maintaining a strong balance sheet and liquidity position.
• Enhancing capital efficiencies through:
utilizing our technical competencies and applying historical learnings from unconventional US shale plays to
reduce US onshore finding and development costs; and
driving Delaware Basin economics through development cycle efficiencies.
• Leveraging the benefits of our well-positioned and diversified portfolio including:
exercising investment optionality and flexibility afforded by our assets, which are largely held by production;
and
continuing portfolio optimization actions to maximize strategic value.
• Capitalizing on a currently low-cost offshore environment with execution of high-quality, long-cycle development
projects, such as:
progressing Leviathan field development.
• Maintaining financial strength through:
focusing operational activities on high-margin, high-return assets;
improving overall corporate returns; and
ensuring cash flow sources and uses remain balanced.
As we enter 2018, we believe we have positioned the Company for sustainability, operational efficiency, and long-term success
throughout the oil and gas business cycle. However, if commodity prices decline or operating costs begin to rise, we could
experience material negative impacts on our revenues, profitability, cash flows, liquidity and proved reserves, and, in response,
we may consider reductions in our capital program or dividends, asset sales or otherwise. Our production and our stock price
could decline as a result of these potential developments. See Item 1A. Risk Factors – The oil and gas industry is cyclical and
an extended period of suppressed commodity prices could have material adverse effects on our operations, our liquidity, and
the price of our common stock.
2018 Production Production may be impacted by factors including:
•
•
•
•
•
•
•
•
•
•
•
commodity prices, which, if subject to decline, could result in current production becoming uneconomic;
overall level and timing of capital expenditures which, as discussed below and dependent upon our drilling success,
will impact near-term production volumes;
increased drilling activity, which may cause US onshore cost inflation pressure and result in certain current production
becoming less profitable or uneconomic;
Israeli industrial and residential demand for electricity, which is largely impacted by weather conditions and the
conversion of Israel's electricity portfolio from coal to natural gas;
timing of the divestiture of the remaining 7.5% working interest in the Tamar and Dalit fields, in accordance with the
Framework, which will leave us with a 25% working interest and will accelerate value realization, but lower our
forward sales volumes;
timing of crude oil and condensate liftings impacting sales volumes in West Africa;
natural field decline in US onshore, Gulf of Mexico and offshore Equatorial Guinea;
additional purchases of producing properties or divestments of operating assets;
potential weather-related volume curtailments due to hurricanes in the Gulf of Mexico and Gulf Coast areas, or winter
storms and flooding impacting US onshore operations;
availability or reliability of supplier services, including access to support equipment and facilities, occurrence of
pipeline disruptions, and/or potential pipeline and processing facility capacity constraints, which may cause delays,
restrictions or interruptions in production and/or midstream processing;
timing and completion of midstream expansion projects by Noble Midstream Partners in areas that provide services to
our assets;
• malfunctions and/or mechanical failures at terminals or other US onshore delivery points;
•
•
•
impact of enhanced completion efforts for US onshore assets;
potential growth from participation in future, or decline from existing, non-operated wells;
abandonment of low-margin US onshore wells;
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•
•
shut-in of US producing properties if storage capacity becomes unavailable; and
potential drilling and/or completion permit delays due to future regulatory changes.
2018 Capital Investment Program
Our 2018 capital investment program is designed to deliver near and long-term value and is flexible in the current commodity
price environment. Excluding capital funded by Noble Midstream Partners, our preliminary 2018 program accommodates an
investment level of approximately $2.7 to $2.9 billion, with approximately 95% being allocated to US onshore development
and the Eastern Mediterranean. The remaining portion of our 2018 capital program is designated for other activities, including
exploration for lease acquisition, seismic and other geological analysis in support of future exploration prospects for potential
development post 2020, as well as other corporate activities.
2018 Budget Principles Our 2018 capital program anticipates a similar level of investment directed to our US onshore assets,
as compared with 2017. We will continue to advance our US onshore program through investments in liquids-rich and high-
return projects, improve execution efficiency, enhance our midstream business value, grow our high margin Delaware Basin
position and invest capital supporting drilling commitments to retain leases in line with our strategy. In the Eastern
Mediterranean, our 2018 capital program accommodates increased investment as we progress toward development of the
Leviathan project. We expect our level of capital investment in the Leviathan project to peak in 2018 and will be supported by
proceeds received from the divestiture of the remaining 7.5% working interest in the Tamar field.
We will evaluate the level of capital spending throughout the year based on the following factors, among others, and their effect
on project financial returns:
•
•
•
•
•
•
•
•
•
•
•
commodity prices, including price realizations on specific crude oil, natural gas and NGL production;
operating and development costs;
production, drilling and delivery commitments, or other contractual obligations;
drilling results;
property acquisitions and divestitures;
exploration activity;
cash flows from operations, including cash flows from potential midstream drop-down transactions;
indebtedness levels;
availability of financing or other sources of funding;
impact of new laws and regulations on our business practices, including potential legislative or regulatory changes
regarding the use of hydraulic fracturing; and
potential changes in the fiscal regimes of the US and other countries in which we operate.
We plan to fund our capital investment program from cash flows from operations, cash on hand, proceeds from divestments of
assets, borrowings under our Revolving Credit Facility, and/or other sources of funding. See Liquidity and Capital Resources –
Cash Flows - Financing Activities, and – Contractual Obligations – Exploration Commitments and Continuous Development
Obligations.
Impact of Recent Changes in US Tax Law
On December 22, 2017, the US Congress enacted the Tax Reform Legislation, making significant changes to US federal
income tax law beginning in 2018. See Item 1A. Risk Factors
While we believe that certain aspects of the new law will positively impact our future after-tax earnings, primarily due to the
lower federal statutory tax rate, the ultimate impact of the Tax Reform Legislation may differ from our estimates due to changes
in interpretations and assumptions made by us as well as additional regulatory guidance that may be issued. See Item 8.
Financial Statements and Supplementary Date – Note 11. Income Taxes.
Potential for Future Impairments
We have had in the past, and may incur in the future, various impairments of proved and unproved properties, related to the
following:
• Exploration Activities and Unproved Properties We may impair and/or relinquish certain undeveloped leases prior to
expiration based upon changes in exploration plans, timing and extent of development activities, availability of capital
and suitable rig and drilling equipment, resource potential, comparative economics, changing regulations and/or other
factors. In addition, in the event we conclude that an exploratory well did not encounter hydrocarbons or that a
discovery or prospect is not economically or operationally viable, the associated capitalized exploratory well costs
would be charged to expense.
• Development Concept Selection Costs We may write-off costs related to certain development concepts, including
costs of related pre-FEED and FEED studies, associated with significant offshore projects, particularly those in remote
or under-developed areas, when such development concepts are eliminated from further consideration based on the
60
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Index to Financial Statements
determination of the final development concept or when the concept itself is determined to be economically
unfeasible.
• Producing Properties We may impair a proved property based on a decrease in forward commodity prices, or
widening of basis differentials, or an increase in abandonment costs, among other factors.
• Divestments We may periodically divest certain assets to reposition our portfolio. When properties meet the criteria
for reclassification as assets held for sale, they are valued at the lower of net book value or anticipated sales proceeds
less transaction-related costs to sell. Impairment expense would be recorded for any excess of net book value over
anticipated sales proceeds less transaction-related costs to sell. In addition, a further loss, which could be material,
could occur upon closing of a sales transaction.
See also: Item 1A. Risk Factors; Item 7. Management's Discussion and Analysis of Financial Condition and Results of
Operations – Exploration Expense; Item 8. Financial Statements and Supplementary Data – Note 5. Asset Impairments and –
Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
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RESULTS OF OPERATIONS – E&P
Highlights for our E&P business were as follows:
2017 Significant E&P Operating Highlights Included:
•
•
•
total average daily sales volumes of 381 MBoe/d;
record average daily sales volumes for US onshore crude oil of 90 MBbl/d; and
average daily sales volumes for natural gas of 272 MMcf/d, net, in Israel, and an all-time record for full year average
daily gross sales volumes for natural gas of 956 MMcfe/d, primarily from the Tamar field.
2017 E&P Financial Results Included:
•
•
•
•
•
average realized crude oil price increase of 23% as compared to 2016;
average realized NGL price increase of 56% as compared to 2016;
average realized natural gas price increase of 24% as compared to 2016;
pre-tax loss of $1.8 billion, as compared with pre-tax loss of $1.3 billion for 2016; and
capital expenditures of $2.4 billion, excluding acquisitions, as compared with $1.2 billion for 2016.
Following is a summarized statement of operations for our E&P business:
(millions)
Oil, NGL and Gas Sales to Third Parties
Income from Equity Method Investees
Total Revenues
Production Expense
Exploration Expense
Depreciation, Depletion and Amortization
Loss on Marcellus Shale Upstream Divestiture (1)
Asset Impairments (2)
(Gain) Loss on Commodity Derivative Instruments
Goodwill Impairment
Clayton Williams Energy Acquisition Expenses (3)
Income (Loss) Before Income Taxes
$
Year Ended December 31,
2016
2015
2017
$
4,060
120
4,180
1,270
188
1,965
2,379
70
(63)
—
100
(1,803)
$
3,389
50
3,439
1,200
925
2,395
—
92
139
—
—
(1,271)
3,093
39
3,132
1,067
488
2,073
—
533
(501)
779
—
(1,699)
(1) See Item 8. Financial Statements and Supplementary Data – Note 4. Acquisitions, Divestitures and Merger.
(2) See Item 8. Financial Statements and Supplementary Data – Note 5. Asset Impairments.
(3) See Item 8. Financial Statements and Supplementary Data – Note 3. Clayton Williams Energy Acquisition.
Revenues
Oil, Gas and NGL Sales Agreements We generally sell crude oil, natural gas, and NGLs under two types of agreements
common in our industry. Both types of agreements may include transportation charges. One type of agreement is a netback
agreement, under which we sell crude oil and natural gas at the wellhead and receive a price, net of transportation expense
incurred by the purchaser. In the case of NGLs, we may receive a price from the purchaser, which is net of fractionation and
processing costs. We record crude oil, natural gas and NGL sales without deductions relating to transportation, fractionation or
processing. These deductions are recorded as production expense.
In addition, commodity prices we receive may be reduced by location-basis differentials, which can be significant. For
example, transportation bottlenecks or infrastructure limitations may increase demand for available transportation and
gathering facilities, which could lead to competitive pricing between operators of a particular area. As a result of location-basis
differentials, our reported sales prices may differ significantly from published commodity price benchmarks for the same
period.
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Average Oil, Gas and NGL Sales Volumes and Prices Average daily sales volumes and average realized sales prices were as
follows:
Sales Volumes
Crude Oil &
Condensate
(MBbl/d)
NGLs
(MBbl/d)
Natural Gas
(MMcf/d)
Total
(MBoe/d) (1)
Average Realized Sales Prices
Crude Oil &
Condensate
(Per Bbl)
NGLs (Per
Bbl)
Natural
Gas
(Per Mcf)
Year Ended December 31, 2017
United States
111
Israel
Equatorial Guinea (2)
Total Consolidated
Operations
Equity Investee (3)
Total
Year Ended December 31, 2016
—
18
129
2
131
United States
Israel
Equatorial Guinea (2)
Total Consolidated
Operations
Equity Investee (3)
Total
99
—
26
125
2
127
Year Ended December 31, 2015
United States
Israel
Equatorial Guinea (2)
Total Consolidated
Operations
Equity Investee (3)
Total
81
—
31
112
2
114
58
—
—
58
6
64
54
—
—
54
5
59
39
—
—
39
5
44
607
272
239
1,118
—
1,118
881
281
235
1,397
—
1,397
708
252
227
1,187
—
1,187
270
$
49.11
$
23.40
$
46
57
373
8
381
301
47
65
413
7
$
$
—
53.68
49.73
55.13
49.84
39.59
—
43.54
40.39
45.44
$
$
—
—
23.40
38.48
24.81
14.92
—
—
14.92
26.30
$
$
420
$
40.46
$
15.96
$
237
$
43.46
$
13.91
$
42
69
348
7
—
48.85
45.00
48.85
—
—
13.91
28.40
355
$
45.05
$
15.59
$
3.02
5.32
0.27
3.01
—
3.01
2.11
5.21
0.27
2.42
—
2.42
2.10
5.34
0.27
2.44
—
2.44
(1) Natural gas is converted on the basis of six Mcf of gas per one barrel of crude oil equivalent. This ratio reflects an energy content
equivalency and not a price or revenue equivalency. Given commodity price disparities, the price for a barrel of crude oil equivalent for
US natural gas and NGLs is 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.
(2) Natural gas from the Alba field is 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) Volumes represent sales of condensate and LPG from Alba Plant in Equatorial Guinea.
63
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Index to Financial Statements
An analysis of revenues from sales of crude oil, natural gas and NGLs is as follows:
(millions)
2015 Sales Revenues
Changes due to
Increase in Sales Volumes
(Decrease) Increase in Sales Prices
2016 Sales Revenues
Changes due to
Increase (Decrease) in Sales Volumes
Increase in Sales Prices
2017 Sales Revenues
Crude Oil &
Condensate
NGLs
Natural
Gas
Total
$
$
$
1,840
$
197
$
1,056
$
3,093
153
(139)
1,854
55
437
2,346
$
$
84
15
296
17
180
493
$
$
190
(7)
1,239
(182)
164
1,221
$
$
427
(131)
3,389
(110)
781
4,060
Crude Oil and Condensate Sales Revenues Revenues from crude oil and condensate sales increased in 2017 as compared with
2016 due to the following:
•
•
•
23% increase in average realized prices due to the partial rebalancing of global supply and demand factors;
higher US onshore sales volumes of 16 MBbl/d, including 5 MBbl/d contributed by recently acquired Clayton
Williams Energy assets, primarily attributable to increased development and enhanced well design and completion
techniques; and
higher sales volumes of 2 MBbl/d due to full year of production at Gunflint, a Gulf of Mexico project that started
production in July 2016;
partially offset by:
•
lower sales volumes of 14 MBbl/d primarily due to natural field decline in the Gulf of Mexico and Equatorial Guinea.
Revenues from crude oil and condensate sales remained relatively flat in 2016 as compared with 2015 due to the following:
•
•
•
higher sales volumes of 9 MBbl/d in the Eagle Ford Shale and Delaware Basin, primarily attributable to full year
consolidation following the Rosetta Merger;
sales volumes from the Big Bend and Dantzler developments (Gulf of Mexico), which began producing fourth quarter
2015 and contributed 12 MBbl/d, net, collectively in 2016; and
sales volume from the start up of the Gulf of Mexico Gunflint development in July 2016 which contributed 3 MBbl/d;
partially offset by:
•
•
10% decrease in total consolidated average realized prices, primarily due to the decline in global crude oil prices that
began in the second half of 2014 and continued into 2016; and
decrease in sales volumes due to natural field decline at the Aseng and Alen fields, offshore Equatorial Guinea.
NGL Sales Revenues Revenues from NGL sales increased in 2017 increased as compared with 2016 due to the following:
•
•
56% increase in average realized prices due to the partial rebalancing of global supply and demand factors; and
higher US onshore sales volumes of 7 MBbl/d, including 1 MBbl/d contributed by recently acquired Clayton Williams
Energy assets, primarily attributable to increased development and enhanced well design and completion techniques;
partially offset by:
•
lower sales volumes of 4 MBbl/d due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017.
Revenues from NGL sales increased in 2016 as compared with 2015 due to the following:
•
•
•
higher sales volumes of 14 MBbl/d in the Eagle Ford Shale and Delaware Basin, primarily attributable to a full year of
production as well as increased development activity;
7% increase in total consolidated average realized prices, primarily due to higher spot prices in the Marcellus Shale;
and
higher sales volumes of 2 MBbl/d in the DJ Basin, primarily attributable to increased well productivity due to
enhanced completion techniques and increased processing capacity;
partially offset by:
•
slightly lower sales volumes in the Marcellus Shale due to the higher dry gas composition of wells that were brought
online in 2016.
Natural Gas Sales Revenues Revenues from natural gas sales decreased slightly in 2017 as compared with 2016 due to the
following:
•
lower sales volumes of 312 MMcf/d due to the divestiture of the Marcellus Shale upstream assets in second quarter
2017; and
64
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Index to Financial Statements
•
lower sales volumes of 29 MMcf/d as a result of the sale of a 3.5% working interest in the Tamar field, offshore Israel,
in December 2016, partially offset by higher gross sales volumes from the field;
partially offset by:
•
•
24% increase in average realized prices due to the partial rebalancing of global supply and demand factors; and
higher US onshore sales volumes of 40 MMcf/d, including 6 MMcf/d contributed by recently acquired Clayton
Williams Energy assets.
Revenues from natural gas sales in 2016 as compared with 2015 due to the following:
•
•
•
•
higher sales volumes of 93 MMcf/d in the Marcellus Shale, primarily attributable to well completion and
infrastructure development;
higher sales volumes of 81 MMcf/d in the Eagle Ford Shale and Delaware Basin, primarily attributable to full year
consolidation following the Rosetta Merger;
record sales volumes from the Tamar field, offshore Israel, which contributed an incremental 29 MMcf/d, in response
to higher power generation needs; and
higher sales volumes offshore Equatorial Guinea due to the completion of the Alba B3 compression project.
Income from Equity Method Investees Our share of operations of equity method investees was as follows:
Year Ended December 31,
2016
2017
2015
Net Income (in millions)
AMPCO and Affiliates
Alba Plant
Dividends (in millions)
AMPCO and Affiliates
Alba Plant
Sales Volumes
Methanol (MMgal)
Condensate (MBbl/d)
LPG (MBbl/d)
Average Realized Prices
Methanol (per gallon)
Condensate (per Bbl)
LPG (per Bbl)
$
$
$
58
65
47
68
163
2
6
$
16
34
16
40
162
2
5
8
31
31
29
117
2
5
$
0.97
55.13
38.48
$
0.63
45.44
26.30
0.92
48.85
28.40
Changes for 2017 as compared with 2016 included the following:
•
•
net income from AMPCO and affiliates increased primarily due to higher realized methanol prices; and
net income from Alba Plant increased primarily due to higher LPG sales volumes and higher realized commodity
prices.
Changes for 2016 as compared with 2015 included the following:
•
•
net income from AMPCO and affiliates increased in 2016 as compared with 2015 primarily due to higher methanol
sales volumes, partially offset by lower methanol prices; and
net income from Alba Plant remained relatively flat.
65
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Index to Financial Statements
Production Expense Components of production expense were as follows:
(millions, except unit rate)
Year Ended December 31, 2017
Lease Operating Expense (3)
Production and Ad Valorem Taxes
Gathering, Transportation and
Processing Expense
Total Production Expense
Total Production Expense per BOE
Year Ended December 31, 2016
Lease Operating Expense (3)
Production and Ad Valorem Taxes
Gathering, Transportation and
Processing Expense
Total Production Expense
Total Production Expense per BOE
Year Ended December 31, 2015
Lease Operating Expense (3)
Production and Ad Valorem Taxes
Gathering, Transportation and
Processing Expense
Total Production Expense
Total Production Expense per BOE
Total per
BOE (1)
Total
United
States (1)
Israel
Equatorial
Guinea
Other
Int'l(2)
$
$
$
$
$
$
4.29
0.99
4.04
9.32
3.72
0.50
3.73
7.95
4.52
0.99
2.88
8.39
$
$
$
$
$
$
$
$
$
585
135
550
1,270
9.32
560
76
564
1,200
7.95
575
126
366
1,067
8.39
$
$
$
$
$
$
$
$
$
466
135
550
1,151
11.68
418
76
564
1,058
9.63
398
126
366
890
10.29
$
$
$
$
$
$
$
$
$
29
—
—
29
1.74
37
—
—
37
2.14
42
—
—
42
2.72
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
90
—
—
90
4.28
105
—
—
105
4.42
131
—
—
131
$
5.21
—
—
—
—
—
—
—
—
—
—
4
—
—
4
N/M
N/M Amount is not meaningful.
(1) United States upstream production expense includes charges from our midstream operations that are eliminated on a consolidated basis.
See Item 1. Financial Statements – Note 15. Concentration of Risk.
(2) Other International includes the North Sea in 2015.
(3) Lease operating expense includes oil and gas operating costs (labor, fuel, repairs, replacements, saltwater disposal and other related
lifting costs) and workover expense.
Lease Operating Expense Lease operating expense increased in 2017 as compared with 2016 primarily due to the following:
•
increase of $82 million in US onshore, primarily in the DJ Basin, Delaware Basin and Eagle Ford Shale due to
increased activity;
partially offset by:
•
•
•
•
decrease of $19 million due to natural field decline in the Gulf of Mexico;
decrease of $17 million related to the divestiture of the Marcellus Shale upstream assets in second quarter 2017;
decrease of $15 million due to various cost reduction initiatives offshore West Africa; and
decrease of $11 million due to a 3.5% lower working interest in the Tamar field, offshore Israel, following the partial
divestiture in December 2016.
Lease operating expense decreased in 2016 as compared with 2015 due to the following:
•
decrease of $92 million in US onshore, primarily in the DJ Basin and Marcellus Shale, and $27 million offshore
Equatorial Guinea due to cost reduction initiatives, including lower equipment utilization and saltwater disposal costs;
partially offset by:
•
•
increase of $74 million attributable to new production from US onshore and Gulf of Mexico development activities;
and
increase of $38 million related to the acquisition of Eagle Ford Shale and Delaware Basin production third quarter
2015.
Production and Ad Valorem Tax Expense Production and ad valorem taxes increased in 2017 as compared with 2016,
primarily due to higher commodity prices and a $28 million US onshore severance tax refund recorded in first quarter 2016
versus a $7 million US onshore severance tax charge recorded in first quarter 2017.
66
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Index to Financial Statements
Production and ad valorem taxes decreased in 2016 as compared with 2015, primarily due to lower revenues and a US onshore
severance tax refund, both driven by a decline in US commodity prices.
Gathering, Transportation and Processing Expense Gathering, transportation and processing expense remained relatively flat
in 2017 as compared with 2016 primarily due to:
•
decrease of $120 million related to the divestiture of the Marcellus Shale upstream assets in second quarter 2017;
partially offset by:
•
•
increase of $57 million in the DJ Basin due to the shifting of crude oil volumes onto a new export pipeline and
contractual increases of pipeline fees; and
increase of $47 million related to higher production in the Delaware Basin and Eagle Ford Shale.
Gathering, transportation and processing expense increased in 2016 as compared with 2015 due to:
•
•
•
•
increase of $66 million related to higher production from our Marcellus Shale assets;
increase of $57 million related to change in mix of transportation methods used for our DJ Basin production;
increase of $49 million related to higher production from our Eagle Ford Shale assets acquired third quarter 2015; and
increase of $17 million related to production from new Gulf of Mexico projects at Big Bend and Dantzler (which
began producing fourth quarter 2015) and Gunflint (which began producing in July 2016).
Unit Rate Per BOE Production expense on a per BOE basis increased in 2017 compared to 2016, primarily due to the
increases in certain production expenses noted above. In addition, the Marcellus Shale upstream divestiture resulted in the
removal of lower-cost, natural gas-focused sales volumes from our portfolio, while an increase in Delaware Basin and Eagle
Ford Shale volumes contributed higher-cost, crude oil-focused sales volumes, thereby increasing our average production
expense per BOE. Also, higher commodity prices led to higher production and ad valorem taxes per BOE.
The unit rate of total production expense per BOE decreased for 2016 as compared with 2015, primarily driven by lower
production and ad valorem taxes as a result of lower commodity prices and lower lease operating expenses as a result of cost
reductions in certain areas, such as equipment utilization and saltwater disposal. The decrease in the unit rate per BOE was
partially offset by higher transportation and gathering expenses due to higher-cost production volumes from certain US onshore
assets.
Exploration Expense Components of exploration expense were as follows:
(millions)
Year Ended December 31, 2017
Leasehold Impairment and Amortization
Dry Hole Cost (4)
Seismic, Geological and Geophysical
Staff Expense
Other (5)
Total Exploration Expense
Year Ended December 31, 2016
Leasehold Impairment and Amortization
Dry Hole Cost (4)
Seismic, Geological and Geophysical
Staff Expense
Other (5)
Total Exploration Expense
Year Ended December 31, 2015
Leasehold Impairment and Amortization
Dry Hole Cost (4)
Seismic, Geological and Geophysical
Staff Expense
Other (5)
Total Exploration Expense
Total
United
States
Eastern
Mediter-
ranean (1)
West
Africa (2)
Other Int'l (3)
$
$
$
$
$
$
62
9
27
55
35
188
148
579
76
77
45
925
113
266
34
43
32
488
$
$
$
$
$
$
60
—
8
1
33
102
123
85
—
3
34
245
105
93
5
—
—
203
$
$
$
$
$
$
— $
—
—
2
—
2
$
— $
26
—
1
7
34
$
5
—
—
1
6
12
$
$
— $
—
—
4
1
5
$
— $
468
10
5
—
483
$
3
33
10
—
—
46
$
$
2
9
19
48
1
79
25
—
66
68
4
163
—
140
19
42
26
227
(1) Eastern Mediterranean includes Israel and Cyprus.
(2) West Africa includes Equatorial Guinea, Cameroon and Gabon.
(3) Other International includes Newfoundland, Suriname and other new ventures.
67
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(4) For a discussion of dry hole cost, see Items 1. and 2. Business and Properties – International – West Africa and Item 8. Financial Statements
(5)
and Supplementary Data – Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
Includes lease rental and other exploration expense.
Exploration expense for 2017 included:
•
•
leasehold impairment expense related primarily to Gulf of Mexico unproved properties; and
dry hole cost of $7 million for the Araku-1 exploration well, offshore Suriname.
Exploration expense for 2016 included:
•
•
leasehold impairment expense including the write-off of leases and licenses of $58 million for the Gulf of Mexico, $25
million for other international locations, and $10 million for other US onshore; and
dry hole cost including costs related to the Silvergate exploratory well, Gulf of Mexico, the Dolphin 1 natural gas
discovery, offshore Israel, and certain discoveries offshore West Africa.
Exploration expense for 2015 included:
leasehold impairment expense including the write-off of our northeast Nevada leases of $21 million;
•
• US dry hole cost including amounts related to northeast Nevada exploration efforts which we elected to discontinue
after assessing commercial viability in the current commodity price environment; and
dry hole cost including the Cheetah well, offshore West Africa, and Other International dry hole cost.
•
Exploration expense included stock-based compensation expense of $7 million in 2017, $10 million in 2016 and $13 million in
2015.
Depreciation, Depletion and Amortization DD&A expense was as follows:
(millions, except unit rate)
Total
United
States
Eastern
Mediter-
ranean
West
Africa
Other Int'l
$
$
$
$
1,965
14.42
Twelve Months Ended December 31, 2017
DD&A Expense
Unit Rate per BOE (1)
Twelve Months Ended December 31, 2016
DD&A Expense
Unit Rate per BOE (1)
Twelve Months Ended December 31, 2015
DD&A Expense
Unit Rate per BOE (1)
N/M Amount is not meaningful.
(1) DD&A expense includes accretion of discount on asset retirement obligations of $47 million in 2017, $48 million in 2016, and $43
2,395
15.87
2,073
16.29
1,677
19.40
1,739
17.65
2,103
19.14
326
12.93
76
4.56
205
8.63
81
4.69
146
6.95
70
4.53
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
4
N/M
6
N/M
—
N/M
million in 2015.
Total DD&A expense decreased in 2017 as compared with 2016 due to the following:
•
•
•
•
•
•
year-end reserve additions, primarily in US onshore due to enhanced well design and completion techniques in our
horizontal drilling program and globally due to positive price revisions. For more information, see reserves discussion
in Supplemental Oil and Gas Information (Unaudited);
slightly lower sales volumes in the DJ Basin and the impact of certain property divestitures since the second quarter
2016;
the Marcellus Shale upstream divestiture in second quarter 2017, which reduced 2017 DD&A expense by $291
million;
the sale of a 3.5% working interest in the Tamar field, offshore Israel, in December 2016, which reduced 2017 DD&A
expense by approximately $7 million;
a reduction in depletable costs of $153 million in the second quarter 2017 due to the reallocation of common asset
costs from the Alen field, offshore Equatorial Guinea, to the West Africa natural gas monetization development
project, which reduced 2017 DD&A expense by $37 million; and
lower sales volumes in the Gulf of Mexico due to natural field decline and reduction in the depletable costs due to
downward revisions in estimates of asset retirement costs;
68
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Index to Financial Statements
partially offset by:
•
•
•
higher US onshore sales volumes of 29 MBoe/d during 2017, including 7 MBoe/d contributed by recently acquired
Clayton Williams Energy assets;
an increase in sales volumes from the Gunflint development, Gulf of Mexico, which commenced production in July
2016; and
higher gross sales volumes from the Tamar field, offshore Israel, due to higher domestic demand.
The unit rate per BOE for 2017 decreased 9% as compared with 2016, primarily due to year-end reserve additions in US
onshore, a reduction in the Alen field net book value in second quarter 2017, and certain DJ Basin property divestitures since
second quarter 2016. These decreases were offset by the commencement of sales volumes from new crude oil-focused wells in
US onshore, as well as the divestiture of natural gas-focused sales volumes from Marcellus Shale upstream assets.
Total DD&A expense increased for 2016 as compared with 2015 due to the following:
•
•
•
increase of $178 million related to higher sales volumes resulting from commencement of production from the Big
Bend, Dantzler and Gunflint development projects in the Gulf of Mexico in 2016 and 2015;
increase of $134 million related to the acquisition of Eagle Ford Shale and Delaware Basin production in third quarter
2015; and
$121 million related to the reduction in proved reserves in fourth quarter 2015, primarily due to downward price
revisions in DJ Basin and Marcellus Shale;
partially offset by:
•
an overall lower segment rate for offshore Equatorial Guinea due to the fluctuation in production from higher DD&A
rate assets, the Aseng and Alen fields, to a lower DD&A rate asset, the Alba field.
The unit rate per BOE for 2016 decreased as compared with 2015, primarily due to lower-cost production volumes from the
Tamar and Alba fields and net book value impairments in fourth quarter 2015 related to downward commodity price revisions.
The decrease in the unit rate per BOE was partially offset by increased higher-cost production volumes from certain US
onshore properties and recently commenced production from Gulf of Mexico assets, including Big Bend, Dantzler and
Gunflint.
RESULTS OF OPERATIONS – MIDSTREAM
The Midstream segment owns, operates, develops and acquires domestic midstream infrastructure assets, with current focus
areas being the DJ and Delaware Basins.
Major Midstream Activities - Noble Midstream Partners During 2017, major activities included the following:
•
•
•
•
progressed the construction and development of multiple major projects in the DJ and Delaware Basins;
began providing crude oil and produced water gathering services to an unaffiliated third party;
entered into the Advantage Joint Venture; and
entered into the Black Diamond Gathering arrangement with definitive agreements to acquire the Saddle Butte system.
Major Midstream Activities - Noble Energy During 2017, we entered into an agreement to sell our 50% interest in CONE
Gathering. We closed the sale in January 2018, receiving cash proceeds of $308 million.
Results of Operations
Highlights for the Midstream segment were as follows:
2017 Midstream Financial Results Included:
•
•
pre-tax income of $233 million, as compared with pre-tax income of $176 million for 2016; and
capital expenditures, excluding acquisitions, of $399 million compared with capital expenditures of $42 million for
2016.
69
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Following is a summarized statement of operations for the Midstream segment:
(millions)
Midstream Services Revenues – Third Party
Income from Equity Method Investees
Intersegment Revenues
Total Revenues
Gathering, Transportation and Processing Expense
Depreciation, Depletion and Amortization
Income Before Income Taxes
Year Ended December 31,
2016
2015
2017
$
$
19
57
277
353
70
30
233
— $
52
200
252
44
19
176
—
51
119
170
25
14
123
Midstream Services and Intersegment Revenues The amount of revenue generated by the Midstream business depends
primarily on the volumes of crude oil, natural gas and water for which services are provided to our E&P business and to third
party customers. These volumes are affected by the level of drilling and completion activity in our areas of upstream operations
and by changes in the supply of, and demand for, crude oil, natural gas and NGLs in the markets served directly or indirectly by
our midstream assets.
Total revenues, excluding income from equity method investees, for 2017 increased from 2016 by $96 million mainly due to
increases of $60 million and $17 million driven by our drilling and completion activities in the DJ and Delaware Basins,
respectively, and an increase of $19 million primarily due to commencement of services in the DJ Basin to an unaffiliated third
party.
Total revenues, excluding income from equity method investees, for 2016 increased from 2015 by $81 million due to our
drilling and completion activities in the DJ Basin.
Income from Equity Method Investees and Other Midstream's share of operations of equity method investees was as follows:
Year Ended December 31,
2016
2015
2017
Net Income (in millions)
CONE Gathering and CONE Midstream
Advantage Pipeline
White Cliffs
Dividends (in millions)
CONE Gathering and CONE Midstream
Gathering, Transportation and Processing Expense
$
$
51
2
4
25
$
48
—
5
27
46
—
—
17
Total expense for 2017 increased by $26 million as compared with 2016 due to the following:
•
•
an increase of $20 million in water services expense due to increased services provided by third parties as well as
higher throughput volumes associated with fresh water services; and
an increase of $6 million in gathering and facilities operating expense due to higher gathered volumes, as well as due
to new systems placed in service and expansion of the gathering infrastructure in 2017.
Total expense for 2016 increased by $19 million as compared with 2015 due to the following:
•
•
an increase of $12 million in water services expense due to an expanded scope of water services delivered; and
an increase of $7 million in gathering systems and facilities operating expense associated with higher gathered
volumes as well as general repairs and maintenance of our gathering systems and facilities.
DD&A Expense
Depreciation. depletion and amortization expense for 2017 increased by $11 million as compared with 2016 due to the assets
placed in service in 2017, specifically assets associated with the construction of the Greeley Crescent facilities and the
Delaware Basin gathering systems, including completion of two CGFs, and expansion of gathering and fresh water systems in
the Wells Ranch, East Pony and Mustang IDP areas.
Depreciation, depletion and amortization expense for 2016 increased by $5 million as compared with 2015 due to assets placed
in service as a result of the expansion of Wells Ranch CGF in 2016 and in second half 2015 and commissioning of the East
Pony crude oil gathering system during 2016.
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RESULTS OF OPERATIONS – CORPORATE
General and Administrative Expense General and administrative expense (G&A) was as follows:
Year Ended December 31,
2016
2017
2015
G&A Expense (millions)
Unit Rate per BOE (1)
$
$
415
3.05
$
$
399
2.64
$
$
396
3.11
(1) Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
G&A expense for 2017 increased slightly as compared with 2016 primarily due to increased employee costs driven by
acquisition activities. The increase in the unit rate per BOE for 2017 as compared with 2016 was due primarily to the decrease
in total sales volumes driven by the divestiture of the Marcellus Shale upstream assets. Our total number of employees
increased from 2,274 at December 31, 2016 to 2,277 at December 31, 2017.
G&A expense for 2016 was flat as compared with 2015 primarily due to sustained cost savings initiatives and decreases in
employee personnel costs. Our total number of employees decreased from 2,395 at December 31, 2015 to 2,274 at December
31, 2016.
G&A expense is impacted by the number of stock-based awards, the market price of our common stock and price volatility
which may result in a higher or lower fair value of stock-based awards as calculated using various valuation models. G&A
expense included stock-based compensation expense of $54 million in 2017, $62 million in 2016 and $50 million in 2015. See
Item 8. Financial Statements and Supplementary Data – Note 12. Stock-Based and Other Compensation Plans.
Other Operating Expense See Item 8. Financial Statements and Supplementary Data – Note 2. Additional Financial Statement
Information for a discussion of our other operating expense.
Loss (Gain) on Extinguishment of Debt See Item 8. Financial Statements and Supplementary Data – Note 10. Long-Term
Debt for discussion of our extinguishment of debt activities.
Interest Expense and Capitalized Interest Interest expense and capitalized interest were as follows:
(millions, except per unit)
Interest Expense
Capitalized Interest
Interest Expense, Net
Unit Rate per BOE (1)
Year Ended December 31,
2016
2017
2015
$
$
$
403
(49)
354
2.60
$
$
$
412
(84)
328
2.17
$
$
$
407
(144)
263
2.07
(1) Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
The decrease in interest expense in 2017 as compared with 2016 is due to the repayment of our Term Loan Facility due January
6, 2019 (Term Loan Facility) and refinancing of our 8.25% senior notes. See Liquidity and Capital Resources - Capital
Structure/Financing Strategy.
The decrease in capitalized interest in 2017 as compared with 2016 is primarily due to the write off of discoveries offshore
Equatorial Guinea, lower work in progress amounts related to major long-term projects, including Gunflint, Gulf of Mexico,
and the Alba B3 compression project, offshore Equatorial Guinea, offset by a higher work in progress amount related to the
Leviathan major long-term development project, offshore Israel.
The increase in interest expense in 2016 as compared with 2015 is primarily due to the impact of senior notes assumed in the
Rosetta Merger during third quarter 2015, a portion of which were subsequently tendered during first quarter 2016 through
proceeds derived from our Term Loan Facility.
The decrease in capitalized interest in 2016 as compared with 2015 is primarily due to lower work in progress amounts related
to major long-term projects, including Big Bend and Dantzler, Gulf of Mexico, which were completed in fourth quarter 2015,
and Gunflint, Gulf of Mexico, and the Alba B3 compression project, offshore Equatorial Guinea, which were completed in July
2016. Additional items that contributed to the decrease in capitalized interest include the farm-out of a portion of Block 12,
offshore Cyprus, during fourth quarter 2015, the write-off of the Humpback dry hole, offshore Falkland Islands, during fourth
quarter 2015 and timing of US onshore activities.
Interest is capitalized on exploration and development projects using an interest rate equivalent to the average rate paid on
long-term debt. Capitalized interest is included in the cost of oil and gas assets and amortized with other costs on a unit-of-
production basis. The majority of the capitalized interest is related to long lead-time projects in the Gulf of Mexico, offshore
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West Africa and offshore Eastern Mediterranean. See Item 8. Financial Statements and Supplementary Data – Note 6.
Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
Income Taxes See Item 8. Financial Statements and Supplementary Data – Note 11. Income Taxes.
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 the commodity price cycle, including a sustained period of low
prices. 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 periodic mergers and acquisitions opportunities, such as the recent Clayton Williams Energy Acquisition.
We endeavor to maintain a strong balance sheet and investment grade credit rating in service of these objectives.
We strive to maintain a minimum liquidity level to address volatility and risk. Traditional sources of our liquidity are cash
flows from operations, cash on hand, available borrowing capacity under our Revolving Credit Facility, and proceeds from
divestitures of properties. 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. We also evaluate potential
strategic farm-out arrangements of our working interests for reimbursement of our capital spending. We may consider
repatriations of foreign cash to increase our financial flexibility and fund our capital investment program. See Operating
Outlook – Impact of Recent Changes in US Tax Law.
During 2017, we focused on implementation of our portfolio transformation strategy and executed a number of divestitures
which generated cash proceeds of over $2 billion. We utilized the proceeds from divestitures to improve our capital structure by
repayment of $1.3 billion of borrowing under our Revolving Credit Facility associated with the Clayton Williams Energy
Acquisition and $550 million of the remaining balance outstanding under our Term Loan Facility due January 6, 2019. To
further strengthen our liquidity profile we performed a series of financing transactions, including retirement of $1 billion of our
8.25% senior notes due March 1, 2019 with the proceeds from issuance of $600 million of 3.85% and $500 million of 4.95%
senior notes due January 15, 2028 and August 15, 2047, respectively. Through the repayment of our Term Loan Facility and
refinancing of our 8.25% senior notes, we effectively eliminated our near-term debt maturities and lowered our future interest
expense by $48 million on an annual basis.
We aim to fund our capital program through operating cash flows and utilize borrowings under our Revolving Credit Facility to
fund additional requirements. In 2017, we borrowed and repaid amounts under our Revolving Credit Facility resulting in $230
million remaining outstanding as of December 31, 2017. Funds were utilized for general corporate purposes and for funding of
our capital development program. As a result of our 2017 financing activities, we ended 2017 with over $4.5 billion in liquidity,
including almost $3.8 billion of availability under our Revolving Credit Facility.
During 2017, we also focused on the continued execution of our integrated midstream strategy through Noble Midstream
Partners. In addition to completion of several key infrastructure assets in the DJ and Delaware Basins, as well as continuing
significant construction activities in the DJ Basin, Noble Midstream Partners purchased certain midstream assets from Noble
Energy for $270 million and expanded its business through entry into certain arrangements to acquire and operate midstream
assets. Funding for these transactions included $312 million raised through the issuance of Noble Midstream Partners common
units and borrowings under the Noble Midstream Services LLC Revolving Credit Facility (Noble Midstream Services
Revolving Credit Facility). As of December 31, 2017, $85 million was outstanding under the Noble Midstream Services
Revolving Credit Facility. Funds were used to partially fund 2017 acquisitions and to finance the midstream capital investment
program. See Item 8. Financial Statements and Supplementary Data - Note 4. Acquisitions, Divestitures and Merger.
In addition, we received $300 million in payments from foreign operations on an outstanding note payable in 2017, leaving a
balance of approximately $434 million that can be repaid without additional US tax impact.
As of December 31, 2017, our outstanding debt (excluding capital lease and other obligations) totaled $6.5 billion. While we
have no near-term debt maturities, we may periodically seek to access the capital markets to refinance a portion of our
outstanding indebtedness.
We may from time to time seek to retire or purchase our outstanding senior notes, and/or seek to improve shareholder returns,
through cash purchases in the open market, privately negotiated transactions or otherwise. Such activities, if any, will depend
on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved
may be material.
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Sources and Uses of Liquidity
Our operating cash flows are a significant source of our liquidity. In 2017, we experienced strengthening crude oil prices and
completed several transformative transactions, repositioning our portfolio from low-margin natural gas-focused assets to high
margin crude oil-rich assets, which significantly contributed to the funding of our capital program. Additional sources of
funding were available through debt financing activities, including borrowings under our Revolving Credit Facility, and
divestment of certain non-strategic oil and gas properties. During 2017, we continued investment in our high cash flow growth
assets and, excluding effects of divestitures, increased production levels from prior years, while also increasing per unit profit
margins. We also improved our financial profile by reducing our debt balance by $255 million with the use of proceeds from
divestments, and decreasing our future interest expense.
For 2018, we will continue our effort to manage our cash flows through capital efficiencies, cost management endeavors, and
focusing on the growth of production from high-margin, high-return assets. With such an approach, nearly all of our 2018
capital investment is allocated to our US onshore plays and the Eastern Mediterranean, specifically the Leviathan development
project, offshore Israel.
Our 2018 production target is in the range of 343 MBoe/d to 353 MBoe/d and we expect our 2018 capital spending program
(excluding acquisitions and Noble Midstream Partners capital), to be in the range of $2.7 to $2.9 billion, or approximately $400
million higher than the 2017 budget. Should WTI and Brent oil prices continue to improve in 2018, we expect future operating
cash flows to increase and provide additional sources of liquidity compared to 2017. We expect to support our investment
program with operating cash flows resulting from our US onshore and Israel offshore assets, with the remainder of the future
capital commitments funded with cash on hand, borrowings under our Revolving Credit Facility and divestment of non-
strategic assets.
We believe our current liquidity level and balance sheet, along with our ability to access the capital markets, provide flexibility
and that we are well-positioned to fund our business throughout the commodity price cycle. We will continue to evaluate the
commodity price environment and our level of capital spending throughout 2018. However, a downgrade or other negative
action with respect to our credit rating could trigger requirements to post collateral as financial assurance of performance under
certain contractual arrangements, potentially impacting our liquidity and/or negatively impacting our cost, terms, conditions
and availability of future financing. See Item 1A. Risk Factors – A downgrade or other negative action with respect to our
credit rating could negatively impact our business and financial condition.
The table below summarizes our cash, debt balances and available liquidity:
(millions, except percentages)
Total Cash (1)
Amount Available to be Borrowed Under Revolving Credit Facility (2)
Total Liquidity
Total Debt (3)
Noble Energy Share of Equity
Ratio of Debt-to-Book Capital (4)
2017
713
3,770
4,483
6,859
10,619
$
$
$
December 31,
2016
$
$
$
1,209
4,000
5,209
7,114
9,600
2015
1,028
4,000
5,028
7,976
10,370
$
$
$
39%
43%
43%
(2)
(1) Total cash at December 31, 2017 includes $18 million cash of Noble Midstream Partners and $37.5 million restricted cash related to the
Saddle Butte acquisition that closed in first quarter of 2018. Total cash at December 31, 2016 includes $57 million cash of Noble
Midstream Partners, and restricted cash of $30 million related to the Delaware Basin property acquisition that closed in January 2017.
In 2017, amount available to be borrowed under the Revolving Credit Facility excludes $265 million and $625 million available to be
borrowed under the Noble Midstream Services Revolving Credit Facility and Leviathan Term Loan Facility (defined below),
respectively, which are not available to Noble Energy for general corporate purposes. In 2016, it excludes $350 million available to be
borrowed under the Noble Midstream Services Revolving Credit Facility. See discussion below.
(3) Total debt includes capital lease and other obligations and excludes unamortized debt discount/premium, and issuance costs.
Our long-term debt (excluding capital lease and other obligations) totaled $6.5 billion at December 31, 2017, with maturities ranging
from 2020 to 2097.
(4) We define our ratio of debt-to-book capital as total debt (which includes long-term debt excluding unamortized discount/premium and
issuance costs, the current portion of long-term debt, and short-term borrowings) divided by the sum of total debt plus Noble Energy's
share of equity. Significant changes in our financial position impacting the ratio included $255 million net decrease in debt, $1.9 billion
increase in shareholders' equity due to issuance of stock as part of consideration paid for Clayton Williams Energy Acquisition, $312
million increase due to issuance of Noble Midstream Partners Common Units and $100 million increase due to stock based
compensation, offset by $190 million decrease in shareholders' equity from dividends paid and $1.1 billion decrease in shareholders'
equity from current year net loss.
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Cash and Cash Equivalents Our cash is primarily denominated in US dollars and invested in money market funds and short-
term deposits with major financial institutions. Approximately $493 million of this cash was attributable to foreign subsidiaries
at December 31, 2017.
Revolving Credit Facilities Noble Energy's Revolving Credit Facility of $4.0 billion matures in 2020. The Noble Midstream
Services Revolving Credit Facility of $350 million matures in 2021. These facilities are used to fund capital investment
programs and acquisitions and may periodically provide amounts for working capital purposes. At December 31, 2017, $230
million was outstanding under the Revolving Credit Facility and $85 million was outstanding under the Noble Midstream
Services Revolving Credit Facility, leaving $3.8 billion and $265 million in remaining availability under the respective credit
facilities. See Item 8. Financial Statements and Supplementary Data - Note 10. Long-Term Debt.
Leviathan Term Loan Facility On February 24, 2017, we entered into a facility agreement (Leviathan Term Loan Facility)
providing for a limited recourse secured term loan facility with an aggregate principal borrowing amount of up to $1 billion, of
which $625 million is initially committed. Any amounts borrowed under the Leviathan Term Loan Facility will be available to
fund a portion of our share of costs for the initial phase of development of the Leviathan field, offshore Israel. To support the
Leviathan development program and to bring first production online by the end of 2019, we may borrow amounts under this
facility in the near-term. As of December 31, 2017, no amounts were drawn under this facility.
Term Loan Facility In fourth quarter 2017, we utilized proceeds received from sale of non-strategic acreage in the DJ Basin to
repay the remaining outstanding balance of $550 million under this $1.4 billion facility. See Item 8. Financial Statements and
Supplementary Data - Note 10. Long-Term Debt.
Senior Notes During 2017 we took steps in managing our long-term debt maturities and liquidity through a series of financing
transactions. We issued $600 million of 3.85% senior unsecured notes that will mature on January 15, 2028 and $500 million of
4.95% senior unsecured notes that will mature on August 15, 2047. We used the proceeds to redeem $1 billion of our 8.25%
senior unsecured notes which were due March 1, 2019. Through these transactions, we effectively enhanced our financial
flexibility and lowered our future cash interest expense by approximately $35 million on an annual basis. See Item 8. Financial
Statements and Supplementary Data - Note 10. Long-Term Debt.
Cash Flows
The following table summarizes our cash flows from operating, investing and financing activities:
Year Ended December 31,
2016
2015
2017
(millions)
Total Cash Provided By (Used in)
Operating Activities
Investing Activities
Financing Activities
Increase (Decrease) in Cash and Cash Equivalents
$
$
$
1,951
(1,606)
(850)
(505) $
1,351
(431)
(768)
152
$
$
2,062
(2,871)
654
(155)
Operating Activities Cash flows from operating activities include all transactions and other events that are not defined as
investing or financing activities and are generally the cash effects of transactions and other events that enter into the
determination of net income.
In 2017, net cash provided by operating activities increased as compared with 2016. The change in cash flows from operating
activities was primarily the result of higher average realized commodity prices partially offset by lower sales volumes and
lower settlements of commodity derivative instruments. The reduction of our sales volumes was mainly driven by the decrease
in sale of natural gas as a result of Marcellus Shale upstream asset divestiture. The increase in cash flows from sales was offset
by the decrease in settlements proceeds from our commodity derivative instruments. The decrease in cash received from
derivative settlements is reflective of an increase in the commodity prices as crude oil and natural gas prices strengthened in the
second half of 2017.
Working capital changes resulted in a $150 million operating cash flow decrease in 2017 as compared with a $460 million
operating cash flow decrease in 2016. The changes in working capital were primarily due to an increase in our current
liabilities, including accrued liabilities and trade payables for drilling and development costs and midstream capital
expenditures. The increase in current liabilities was partially offset by the increase in accounts receivable resulting from higher
revenues and higher joint interest billing receivables, primarily due to billings associated with Leviathan development project
costs.
In 2017, we made cash interest payments related to outstanding debt of $394 million as compared to $412 million in 2016.
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In 2016, net cash provided by operating activities for 2016 decreased as compared with 2015. Decreases in average realized
commodity prices and lower settlements of commodity derivative instruments were partially offset by increases in sales
volumes. Working capital changes resulted in a $460 million operating cash flow reduction in 2016 as compared with a
negative impact of $129 million in 2015 and were due primarily to decreases in capital accruals related to reduced development
activity, as well as an increase in accounts receivable related to higher revenues.
In 2016, we made cash interest payments related to outstanding debt of $412 million as compared to $404 million in 2015.
Investing Activities Our investing activities include capital spending on a cash basis for oil and gas properties and midstream
infrastructure and investments in unconsolidated subsidiaries accounted for by the equity method. These investing activities
may be offset by proceeds from property sales or dispositions, including farm-out arrangements, which may result in
reimbursement for capital spending that had occurred in prior periods.
In 2017, capital spending for additions to property, plant and equipment, excluding acquisitions, totaled $2.6 billion compared
to $1.5 billion in 2016. Approximately $700 million of the increase was due to increased US onshore development activity in
response to a more favorable commodity price environment, as well as our focus on development of high margin areas in the
DJ and Delaware Basins, and approximately $416 million increase was related to the initial Leviathan project development.
In addition, we used $637 million of cash, net of $21 million of cash acquired, to fund a portion of the consideration paid in
the Clayton Williams Energy Acquisition, and we acquired Delaware Basin and other assets for $327 million.
In 2017, we received net cash proceeds of over $2 billion from divestitures of non-core assets, including:
•
•
•
$1.0 billion from the Marcellus Shale upstream divestiture;
$568 million on the sale of Greeley Crescent and Bronco acreage in the DJ Basin; and
$335 million from the sale of mineral and royalty assets.
See Item 8. Financial Statements and Supplementary Data - Note 3. Clayton Williams Energy Acquisition and Note 4.
Acquisitions, Divestitures and Merger.
We utilized these sales proceeds to partially fund our Clayton Williams Energy Acquisition, support our development activities
in core operational areas, repay outstanding balances under the Term Loan Facility and further strengthen our liquidity position.
Other investing activities provided a net $87 million of cash as of December 31, 2017.
In comparison, capital expenditures in 2016 were $1.5 billion or nearly half of capital spent in 2015 due to the timing of
completion of major project development activities in the Gulf of Mexico, DJ Basin and Marcellus Shale. We received
approximately $1.2 billion of proceeds from asset divestitures during 2016 as compared with $151 million of proceeds from
divestitures during 2015. In 2016, we invested $8 million in CONE Gathering, and received cash distributions of $70 million,
accounted for as investing activity, from CONE Midstream.
In 2015, capital spending for property, plant and equipment was $3.0 billion, representing a decrease of $1.9 billion as
compared with 2014, primarily due to decreased major project development activity in our operational areas. We received $151
million of proceeds from asset divestitures during 2015 as compared with $321 million proceeds from divestitures during 2014,
and acquired cash of $61 million in the Rosetta Merger. We also invested $104 million in CONE Gathering in 2015.
Financing Activities Our financing activities include the issuance or repurchase of Noble Energy common stock and Noble
Midstream Partners common units, payment of cash dividends to Noble Energy shareholders and cash distributions to Noble
Midstream Partners noncontrolling interest owners, and debt transactions.
In 2017, our primary financing activities included $230 million net Revolving Credit Facility borrowings (including the
borrowing and repayment of $1.3 billion associated with the Clayton Williams Energy Acquisition), $85 million net Noble
Midstream Services Revolving Credit Facility borrowings used primarily to fund an acquisition, a $1.1 billion senior note
refinancing, $595 million related to the repayment of Clayton Williams Energy debt, and a $550 million Term Loan Facility
repayment. In addition, we received $312 million net proceeds from the issuance of Noble Midstream Partners common units,
paid $190 million of cash dividends and $28 million of cash distributions, and made $60 million of capital lease principal
payments.
We also received $10 million cash proceeds from the exercise of stock options and purchased 1,031,000 shares of treasury
stock with a value of $36 million. These shares included 719,849 shares with a value of $25 million related to vesting of
Clayton Williams Energy restricted stock and options in connection with the Clayton Williams Energy Acquisition. The
remaining shares were surrendered for the payment of withholding taxes due on the vesting of employee restricted stock
awards.
In 2016, we used Term Loan Facility proceeds of $1.4 billion to redeem $1.4 billion of senior notes. We subsequently repaid
$850 million of the Term Loan Facility from cash on hand. We received $299 million net proceeds from the issuance of Noble
Midstream Partners common units in a public offering. Funds were also provided by cash proceeds from, and tax benefits
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Index to Financial Statements
related to, the exercise of stock options ($18 million). We used cash to pay dividends on our common stock ($172 million),
make principal payments related to capital lease obligations ($53 million), and repurchase 237,000 shares of our common stock
($4 million).
In 2015, we received approximately $1.1 billion net proceeds from the issuance of shares of common stock in a public offering.
Funds were also provided by cash proceeds from, and tax benefits related to, the exercise of stock options ($7 million). We
used cash to pay dividends on our common stock ($291 million), make principal payments related to capital lease obligations
($67 million), and repurchase 491,000 shares of our common stock ($21 million). Subsequent to the Rosetta Merger, we
incurred financing cash outflows to facilitate the exchange of Rosetta's debt ($12 million) as well as repay the balance
outstanding under Rosetta's credit facility ($70 million).
See Item 8. Financial Statements and Supplementary Data – Consolidated Statements of Cash Flows.
Dividends We paid cash dividends totaling 40 cents per common share in 2017, 40 cents per common share in 2016, and 72
cents per common share in 2015. See Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities.
Acquisition, Capital Expenditures and Other Exploration Expenditures
Our capital expenditures (on an accrual basis) were as follows for the year ended December 31, 2017:
Year Ended December 31,
2016
2015
2017
(millions)
Acquisition, Capital and Exploration Expenditures
Unproved Property Acquisition (1)
Proved Property Acquisition (2)
Exploration
Development
Midstream(3)
Corporate and Other
Total
Other
Investment in Equity Method Investee (4)
Increase in Capital Lease Obligations (5)
$
$
$
$
$
$
1,817
839
42
2,310
480
34
5,522
68
—
$
$
$
234
—
222
1,017
42
50
1,565
8
5
1,480
1,613
322
2,055
356
97
5,923
104
55
(1)
(2)
(3)
(4)
2017 costs include $1.6 billion related to the Clayton Williams Energy Acquisition and $246 million related to the Delaware Basin asset
acquisition.
2016 costs relate to properties exchanged with CONSOL upon termination of the Marcellus Shale joint development agreement.
2015 costs include $1.4 billion related to the Rosetta Merger.
2017 costs include $722 million of proved properties and $63 million of asset retirement obligations acquired in the Clayton Williams
Energy Acquisition and $58 million related to the Delaware Basin asset acquisition.
2015 costs of $1.6 billion are related to the Rosetta Merger.
2017 includes gathering and processing assets of $48 million related to the Clayton Williams Energy Acquisition.
2016 includes Noble Midstream Partners expenditures.
2015 includes midstream assets acquired in the Rosetta Merger.
2017 includes our contribution to the Advantage Joint Venture, in which Noble Midstream Partners owns a 50% interest.
2015 includes investments in CONE Gathering, in which we previously owned a 50% interest. See Item 8. Financial Statements and
Supplementary Data - Note 4. Acquisitions, Divestitures and Merger.
(5) Relates to US onshore assets.
Total capital expenditures increased during 2017 as compared with 2016 as we pursued strategic portfolio repositioning through
a number of acquisitions in our core onshore operational areas in the Delaware Basin and also continued execution of our
midstream capital investment program through Noble Midstream Partners. The increase in development capital is in response to
the strengthening of commodity prices in the second half of 2017 and is primarily related to drilling and development costs of
$1.9 billion incurred mainly in our three US onshore plays (DJ Basin, Delaware Basin and Eagle Ford Shale). Additionally,
$416 million of capital expenditures in 2017 was associated with the initial Leviathan project development, while in 2016 we
incurred $106 million of project development costs, offshore Israel.
In 2016, total expenditures decreased as compared with 2015, excluding acquisition costs of $3.2 billion related to the Rosetta
Merger, as we responded to the lower commodity price environment.
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2015 expenditures, excluding the Rosetta Merger, reflect our reduced capital spending program. Given the 2015 commodity
price environment and an industry cost structure that had yet to fully reset to lower revenue levels, we designed a substantially
reduced capital investment program that was appropriate for the price environment.
Off-Balance Sheet Arrangements
We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations.
As of December 31, 2017, material off-balance sheet arrangements and transactions that we have entered into included drilling
rig contracts, transportation and gathering agreements, operating lease agreements, and undrawn letters of credit, all of which
are customary in the oil and gas industry (see cross references to the Notes to the Financial Statements in the table below).
Other than these aforementioned arrangements, we have no transactions, arrangements or other relationships with
unconsolidated entities or other persons that are reasonably likely to materially affect our financial condition, results of
operations, liquidity or availability of or requirements for capital resources. See also Contractual Obligations below.
Contractual Obligations
The following table summarizes certain contractual obligations as of December 31, 2017 that are reflected in the consolidated
balance sheets and/or disclosed in the accompanying notes. Unless otherwise noted, all amounts shown are net to our interest.
Obligation
Note
Reference (1)
Total
2018
2019 and
2020
2021 and
2022
2023 and
beyond
(millions)
Long-Term Debt (2)
Interest Payments (3)
Capital Lease and Other Obligations (4)
Drilling and Equipment Obligations (5)
Purchase Obligations (6)
Transportation and Gathering (7)
Operating Lease Obligations (8)
Other Liabilities (9)
Note 10
Note 10
Note 10
Note 17
Note 17
Note 17
Note 17
Note 12
Asset Retirement Obligations (10)
Note 9
Commodity Derivative Instruments (11) Note 8
Total Contractual Obligations
$
$
6,586
5,804
335
448
448
2,474
330
— $
324
74
343
293
215
44
$
230
645
87
105
101
499
65
875
68
17,368
$
$
51
53
1,397
$
267
15
2,014
$
1,464
555
50
—
22
405
65
99
—
2,660
$
$
4,892
4,280
124
—
32
1,355
156
458
—
11,297
(1) References are to the Notes accompanying Item 8. Financial Statements and Supplementary Data.
(2) Long-term debt excludes capital lease obligations and includes our fixed rate debt and revolving credit facilities balances based on the
maturity dates of the facilities.
(3)
Interest payments are based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2017.
(4) Annual capital lease payments, net to our interest, exclude regular maintenance and operational costs.
(5) Drilling and equipment obligations represent our working interest share of contractual agreements with third-party service providers to
procure drilling rigs and other related equipment for exploratory and development drilling activities. See Counterparty Credit Risk,
above.
(6) Purchase obligations represent our working interest share of contractual agreements to purchase goods or services that are enforceable,
are legally binding and specify all significant terms, including fixed and minimum quantities to be purchased; fixed, minimum or
variable price provisions; and the approximate timing of the transaction. See Counterparty Credit Risk, above.
(7) Transportation and gathering obligations represent minimum charges for firm transportation and gathering agreements related to our
production. See Items 1. and 2. Business and Properties – Delivery and Firm Transportation Commitments.
(8) Operating lease obligations represent non-cancelable leases for office buildings and facilities and oil and gas operations equipment used
in our daily operations. Amounts have not been discounted.
(9) The table excludes deferred compensation liabilities of $197 million as specific payment dates are unknown.
(10) Asset retirement obligations are discounted.
(11) Amount represents open commodity derivative instruments that were in a net payable position with the counterparty at December 31,
2017.
Exploration Commitments The terms of some of our PSCs, licenses or concession agreements may require us to conduct
certain exploration activities, including drilling one or more exploratory wells or acquiring seismic data, within specific time
periods. These obligations can extend over periods of several years, and failure to conduct such exploration activities within the
prescribed periods could lead to loss of leases or exploration rights. Our exploration commitments currently include 3D seismic
obligations for certain international locations.
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Continuous Development Obligations Although the majority of our assets are held by production, certain of our US onshore
assets, such as our Eagle Ford Shale and Delaware Basin properties, are held through continuous development obligations.
Therefore, we are contractually obligated to fund a level of development activity in these areas which could be substantial.
Failure to meet these obligations may result in the loss of a lease.
Leviathan Natural Gas Project The initial development of the Leviathan field requires substantial infrastructure and capital.
We have executed major equipment and installation contracts in support of development activities. As of December 31, 2017,
we had entered into contracts with remaining obligations of approximately $464 million, net, to support development and bring
first production online by the end of 2019.
Marcellus Shale Firm Transportation Agreements In connection with the Marcellus Shale upstream divestiture, we reduced
our firm transportation financial commitments through the transfer of several contracts to the acquirer and retained certain other
firm transportation contracts representing a total financial commitment of approximately $1.4 billion, undiscounted, primarily
with remaining contract terms of two to 16 years.
One of the retained contracts relates to the Texas Eastern Pipeline, a major interstate natural gas transmission pipeline
delivering natural gas to the northeastern US. This contract will be fully utilized through an agreement with the acquirer,
whereby the acquirer will deliver quantities of natural gas to us and receive a netback sales price that reflects the value received
by us at the sales point, less our effective fixed transportation fees and other expenses, plus a margin. This contract represents
an undiscounted financial commitment of approximately $114 million as of December 31, 2017, before offset by the netback
agreement, thus reducing the remaining overall commitment noted above.
Two of the retained contracts relate to the Leach Xpress and Rayne Xpress projects. These are interstate natural gas
transmission pipelines, which were completed and placed in service in late 2017 and early 2018 to transport production from
the Marcellus Shale to markets outside the basin. In fourth quarter 2017, we permanently assigned a portion of our retained
capacity to a third party and reduced our remaining undiscounted financial commitment to approximately $418 million. At this
time, we are unable to predict with certainty the outcome of our commercialization activities, our ability to utilize retained
capacity and the timing of when we may recognize a non-cash exit cost in line with accounting for exit costs associated with
these two pipeline projects.
Two additional retained contracts relate to the NEXUS and WB Xpress projects. These projects also include interstate natural
gas transmission pipelines designed to transport production from the Marcellus Shale to markets outside the basin. Both
projects have received FERC approval, will undergo construction activities and are targeted for in-service late 2018. These
contracts represent an undiscounted financial commitment of approximately $870 million.
We are currently engaged in actions to commercialize and address these remaining commitments, which provide for the
transportation of approximately 450,000 MMBtu/d of natural gas. Actions include the permanent assignment of capacity,
negotiation of capacity release, utilization of capacity through purchase of third party natural gas, and other potential
arrangements. In addition, we have a “call” or right to purchase natural gas, priced at a regional index, from the acquirer of the
Marcellus Shale upstream assets. This call extends through July 1, 2022 and may be exercised on quantities of the acquirer's
production between 431,100 MMBtu/d and 832,645 MMBtu/d.
We expect these actions, some of which may require pipeline and/or FERC approval, to ultimately reduce the financial
commitment associated with these contracts. At the date each pipeline is placed in service and our commitment begins, we will
evaluate our position. If we determine that we will not utilize a portion, or all, of the contracted pipeline capacity, we will
accrue a liability, at fair value, for the net amount of the estimated remaining financial commitment and include the related
expense in operating expense in our consolidated statements of operations.
In accordance with US GAAP, we recognize the fair value of a liability for an exit cost in the period in which a liability is
incurred. As a result, in second quarter 2017, we accrued non-cash exit costs of $41 million, discounted, relating to our
transportation contract with the Appalachian Gateway Project (Gateway). Gateway, another natural gas transmission pipeline, is
currently in service. We no longer have production to satisfy this commitment and do not plan to utilize this capacity in the
future. In addition, we recorded a $52 million accrual, discounted, in fourth quarter 2017 relating to future commitments to the
third party who assumed a portion of our capacity on the Leach Xpress and Rayne Xpress Projects. Both charges are included
in loss on Marcellus Shale upstream divestiture in our consolidated statements of operations. See Item 8. Financial Statements
and Supplementary Data – Note 17. Commitments and Contingencies.
Other US Transportation Agreements Certain of these contracts require us to make payments for any shortfalls in delivering or
transporting minimum volumes under the commitments. As properties are undergoing development activities, we may
experience temporary shortfalls until production volumes increase to meet or exceed the minimum volume commitments and
will incur expense related to volume deficiencies and/or unutilized commitments. These amounts are recorded as marketing
expense in our consolidated statements of operations. We expect to continue to incur expense related to deficiency and/or
unutilized commitments in the near-term. Should commodity prices decline or if we are unable to continue to develop our
properties as planned, or certain wells become uneconomic and are shut-in, we could incur additional shortfalls in delivering or
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transporting the minimum volumes, and we could be required to make payments in the event that these commitments are not
otherwise offset. We continually seek to optimize under-utilized assets through capacity release and third-party arrangements,
as well as, for example, through the shifting of transportation of production from rail cars to pipelines when we receive a higher
netback price. We may continue to experience these shortfalls both in the near and long-term. Item 8. Financial Statements and
Supplementary Data – Note 2. Additional Financial Statement Information
OIL Contingency As of December 31, 2017, we accrued approximately $19 million for an insurance contingency due to our
membership in OIL. OIL is a mutual insurance company which insures specific property, pollution liability and other
catastrophic risks. As part of our membership, we are contractually committed to pay termination fees should we elect to
withdraw from OIL. We do not anticipate withdrawing from OIL; however, the potential termination fee is calculated annually
based on OIL’s past losses, and the liability reflecting this potential charge has been accrued as of December 31, 2017.
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 totaled
approximately $90 million at December 31, 2017.
Ratings Triggers We do not have triggers on any of our corporate debt that would cause an event of default in the case of a
downgrade of our credit rating. In addition, there are no existing ratings triggers in any of our commodity hedging agreements
that would require the posting of collateral. However, a series of downgrades or other negative rating actions could increase our
cost of financing, and may increase our requirements to post collateral as financial assurance of performance under certain
other contractual arrangements such as pipeline transportation contracts, crude oil and natural gas sales contracts, work
commitments and certain abandonment obligations. A requirement to post collateral could have a negative impact on our
liquidity.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of the consolidated financial statements requires our management to make a number of estimates and
assumptions relating to the reported amounts of assets and liabilities and the disclosures of contingent assets and liabilities at
the date of the consolidated financial statements and the reported amounts of revenues and expenses during the period. When
alternatives exist among various accounting methods, the choice of accounting method can have a significant impact on
reported amounts. The following is a discussion of the accounting policies, estimates and judgments which management
believes are most significant in the application of US GAAP used in the preparation of the consolidated financial statements.
Reserves
Description All of the reserves data in this Annual Report on Form 10-K are estimates. Estimates of our crude oil, natural gas
and NGL reserves are prepared by our qualified petroleum engineers in accordance with guidelines established by the SEC.
Reservoir engineering is a subjective process with numerous uncertainties inherent in estimating underground accumulations of
crude oil, natural gas and NGLs, including the projection of future production rates and the expected timing of development
expenditures. In addition, economic producibility of reserves is dependent on the commodity prices used in the reserves
estimate. Our reserves estimates are based on historical 12-month average commodity prices, unless contractual arrangements
designate the price to be used, in accordance with SEC rules.
Reserves estimates impact our financial statements and disclosures, as the estimates are used as an input in calculation of our
DD&A expense, assessment of impairment of crude oil and natural gas properties and in preparation of Supplemental Oil and
Gas Disclosures.
Judgment and Uncertainties The accuracy of any reserves estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment. Commodity prices and development and production costs are factors
used in determining reserves economics and reserves estimates. As a result, our reserves estimates will change in the future due
to commodity price volatility and cost changes, as well as due to new information obtained from development drilling and
production history.
Effect if Actual Results Differ from Assumptions Our reserves estimates are based on year-end cost, development, production
and historical 12-month average price data. Results of drilling, testing, and production subsequent to the date of the estimate
may justify revision of such estimate. Accordingly, reserves estimates are often different from the quantities of crude oil,
natural gas and NGLs that are ultimately recovered due to reservoir performance and new geological and geophysical data.
Additionally, increases in future drilling, development, production and abandonment costs and changes in commodity prices
may result in future revisions to our reserves.
Estimates of proved crude oil, natural gas and NGL reserves significantly affect our DD&A expense. For example, if estimates
of proved reserves decline, the DD&A rate will increase, resulting in a decrease in net income. A decline in estimates of proved
reserves could also cause us to perform an impairment analysis to determine if the carrying amount of crude oil and natural gas
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properties exceeds the fair value and could result in an impairment charge, which would reduce earnings. See Item 8. Financial
Statements and Supplementary Data - Supplemental Oil and Gas Information (Unaudited).
Oil and Gas Properties - Successful Efforts Method of Accounting
Description We account for crude oil and natural gas properties under the successful efforts method of accounting.
Application of the successful efforts method results in the capitalization of costs directly related to specific oil and gas reserves
when results are positive and expensing of certain costs, including geological and geophysical costs and delay rentals, during
the periods the costs are incurred, and, in the case of dry hole costs, in the period the well is deemed non-commercial.
Under the successful efforts method, we capitalize the following:
• Acquisition costs - Costs associated with the purchase, lease or other costs to acquire mineral interests in crude oil and
natural gas properties are initially capitalized as unproved property acquisition costs. These costs are commonly
attributable to undeveloped leasehold costs or are derived from allocated fair values as a result of business
combinations. Continued capitalization of these costs is dependent upon discovery of proved reserves. For example:
If no proved reserves are discovered after exploration, drilling or lapse of the lease, then costs are impaired.
As part of our periodic impairment review, we review undeveloped leasehold costs for potential impairment
and if, based upon a change in exploration plans, timing and extent of development activities, availability of
capital and suitable rig and drilling equipment, resource potential, comparative economics, changing
regulations and/or other factors, an impairment is indicated, we will record impairment expense related to the
respective lease.
When we have allocated fair values to a significant unproved property (probable and/or possible reserves) as
the result of a business combination or other purchase of proved and/or unproved properties, we use a future
cash flows analysis to assess the property for impairment. Cash flows used in the impairment analysis are
determined based upon management’s estimates of probable and possible reserves, future commodity prices,
and future costs to produce the reserves. Probable reserves are defined in SEC Regulation S-X, Rule 4-10(a)
(18) as those additional reserves that are less certain to be recovered than proved reserves but which, together
with proved reserves, are more likely than not (generally having more than 50% probability) to be recovered.
Possible reserves are defined in SEC Regulation S-X, Rule 4-10(a)(17) as those additional reserves that are
less certain to be recovered than probable reserves. Estimates of cash flows related to probable and possible
reserves are reduced by additional risk-weighting factors.
If undiscounted future net cash flows are less than the carrying value of the property, indicating impairment,
the cash flows are discounted using a risk-adjusted rate and compared to the carrying value to determine the
amount of the impairment loss to record.
If proved reserves are discovered, the related acquisition costs are reclassified to proved properties. We
assess proved crude oil and natural gas properties and other investments for possible impairment whenever
events or circumstances indicate that the recorded carrying values of the assets may not be recoverable. We
recognize an impairment loss as a result of an event that causes us to consider the possibility that impairment
may have occurred and when the estimated undiscounted future net cash flows from a property or other
investment are less than the carrying value.
If impairment is indicated, the carrying values are written down to fair value, which, in the absence of
comparable market data, is estimated using a discounted cash flow method. In our cash flow method, cash
flows are discounted using a risk-adjusted rate and compared to the carrying value for determining the
amount of the impairment loss to record. Estimated future net cash flows are based on management’s
expectations for the future and include estimates of crude oil, natural gas and NGL reserves and future
commodity prices, adjusted for location and quality differentials, revenues and operating and development
costs.
• Exploratory well costs - Costs associated with drilling an exploratory well may be capitalized temporarily, or
“suspended,” pending a determination of whether crude oil or natural gas have been discovered and can be estimated
with reasonable certainty to be economically producible. We carry the costs of an exploratory well as an asset if we
have found a sufficient quantity of reserves to justify its completion as a producing well and as long as we are making
sufficient progress assessing the reserves and the economic and operating viability of the project. For certain capital-
intensive Gulf of Mexico or international projects, it may take several years to evaluate the future potential of the
exploratory well and make a determination of its economic viability. Our ability to move forward on a project may be
dependent on gaining access to transportation or processing facilities or obtaining permits and government or partner
approval, the timing of which is beyond our control. In such cases, exploratory well costs remain suspended as long as
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we are actively pursuing access to necessary facilities and submitting requests for permits and approvals and believe
they will be obtained.
• Development well costs - Costs associated with drilling a development well to obtain access to and to produce proved
reserves are capitalized. Development well costs are included in our periodic proved property impairment test noted
above.
These costs, along with those for support equipment and facilities, are amortized to expense by the unit-of-production method
on a field-by-field basis, based on total proved crude oil, natural gas and NGL reserves, as estimated by our qualified petroleum
engineers. Costs of certain gathering facilities or processing plants serving a number of properties or used for third-party
processing are depreciated using the straight-line method over the useful lives of the assets.
The alternative method of accounting for crude oil and natural gas properties is the full cost method. Under the full cost
method, geological and geophysical costs, exploratory dry holes and delay rentals are capitalized as assets and charged to
earnings in future periods as a component of DD&A expense. In addition, under the full cost method, capitalized costs are
accumulated in pools on a country-by-country basis. DD&A is computed on a country-by-country basis, and capitalized costs
are limited on the same basis through the application of a ceiling test.
Judgment and Uncertainties The determination of the carrying value of our oil and gas properties includes assessment of
impairment and the calculation of amortization expense.
In determination of whether significant unproved crude oil and natural gas properties are impaired, we apply a significant
amount of judgment in assessing entity-specific assumptions and assumptions related to the future economic environment, as
well as potential impacts of the political and regulatory climate on future development activity. We also consider numerous
factors including, but not limited to, current exploration plans, favorable or unfavorable exploration activity on the property
being evaluated and/or adjacent properties, our geologists' evaluation of the property, and the remaining months in the lease
term for the property. In addition, impairment assessment involves a high degree of estimation uncertainty as it requires us to
make assumptions and apply judgment to estimate future cash flows related to proved and unproved reserves. Such
assumptions include commodity prices, capital spending, production and abandonment costs and reservoir data. Significant
judgment is involved in estimating these factors, and they include uncertainties. In cases where probable and possible reserves
cash flows are utilized to assess properties for impairment, we use the same pricing, cost and future production assumptions.
We apply significant judgment in determining whether sufficient progress has been made in assessing the reserves and the
economic and operational viability of a project to continue capitalization of the exploratory well costs. Such assessment
requires consideration of the following factors: commitment of project personnel, costs incurred to assess reserves and potential
development, assessment process in progress covering economic, legal, political and environmental aspects of potential
development, existence or active negotiations of agreements with governments and venture partners or sales contracts with
customers, identification of existing transportation and other infrastructure that is or will be available for the project and other
factors. Consideration of these factors requires us to make assumptions and apply judgment to assess industry and economic
conditions, as well as our future drilling and development plans. Future changes in our exploratory and drilling activities or
economic conditions may result in determination not to pursue certain projects, resulting in future write-offs of the capitalized
exploratory well costs.
Calculation of unit-of-production rates is performed on a field-by-field basis and includes estimation of the period-end reserves
base and production data for each respective field, including estimates of production for non-operated properties.
Effect if Actual Results Differ from Assumptions We have not made any material changes in the accounting methodology we
use to account for our oil and gas properties. We believe the successful efforts method is the most appropriate method to use in
accounting for our crude oil and natural gas properties because it provides a better representation of our results of operations,
especially during periods of active exploration. If we had used the full cost method, our financial position and results of
operations could have been significantly different.
At December 31, 2017, the net book value of our unproved properties includes significant amounts allocated in previous
business combinations or acquisitions, including the Clayton Williams Energy Acquisition and the Rosetta Merger. See
Supplemental Oil and Gas Information (Unaudited) - Capitalized Costs Relating to Oil and Gas Producing Activities.
Unfavorable revisions to our reserves and/or changes in our exploration and development plans or the economic, political or
regulatory environment in areas where we operate, or changes in the availability of funds for future activities may result in
abandonment and impairment of unproved leases and oil and gas properties. During 2017 we recognized undeveloped
leasehold impairment expense of $62 million primarily attributable to Gulf of Mexico leases. We recorded leasehold
impairment expense of $93 million in 2016 and $21 million in 2015.
Impairment assessment incorporates expected future cash flows using expected prices, cost rates and future production. For the
purpose of impairment testing, we used the five-year strip prices for crude oil and natural gas, with prices subsequent to the
fifth year held constant as the benchmark price, unless contractual arrangements designate the price to be used, in the
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undiscounted future net cash flows. Capital and operating costs were estimated assuming 0% escalation. Unfavorable changes
in these pricing and cost assumptions in the future may result in negative revisions to our reserves and associated cash flows,
causing us to record impairment of proved oil and gas properties. We recorded total pre-tax (non-cash) impairment charges of
$70 million in 2017, $92 million in 2016, and $533 million in 2015 for proved oil and gas properties. See Item 8. Financial
Statements and Supplementary Data - Note 5. Asset Impairments.
At December 31, 2017, the balance of property, plant and equipment included $520 million of suspended exploratory well
costs, $510 million of which had been capitalized for a period greater than one year. The wells relating to these suspended costs
continue to be evaluated by various means, including additional seismic work, drilling additional appraisal wells to confirm the
size of the hydrocarbon deposit, or evaluating the potential commerciality of the exploratory wells. During 2017, previously
capitalized exploratory well costs of $65 million were expensed. See Item 8. Financial Statements and Supplementary Data -
Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
Additionally, the carrying value of our oil and gas properties is sensitive to reserves estimates. Unit-of-production rates are
revised at least once a year or when the reserves estimates are updated due to major revisions or transactions. The change in
unit-of-production rates will affect the carrying value of our oil and gas properties and DD&A expense. If the estimates of
proved reserves used in the unit-of-production calculations had been lower by 10% across all properties, 2017 DD&A expense
would have increased by approximately $210 million.
Furthermore, a change in groupings of our oil and gas properties for the purpose of the DD&A calculation and impairment
review could affect the calculation of unit-of-production rates, DD&A expense and determination of impairment.
Asset Retirement Obligations
Description Our asset retirement obligations (AROs) consist of estimated costs of dismantlement, removal, site reclamation
and similar activities associated with our oil and gas properties. We recognize the fair value of an ARO liability in the period in
which it is incurred, which is when we have an existing legal obligation associated with the retirement of our oil and gas
properties and the obligation can be reasonably estimated.
The associated asset retirement cost is capitalized as part of the carrying cost of the oil and gas asset. In determining the fair
value of an ARO, we utilize the estimated future cash flows method. The recognition of an ARO requires that management
make numerous estimates, assumptions and judgments regarding such factors as: the existence of a legal obligation for an
ARO; estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation
rates.
In periods subsequent to initial measurement of the ARO, we recognize period-to-period changes in the liability resulting from
the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted future cash flows.
Revisions also result in increases or decreases in the carrying cost of the oil and gas asset. Increases in the ARO liability due to
passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to
expense through DD&A or exploration expense.
Judgment and Uncertainties The process for determining the fair value of an ARO requires us to make subjective judgments
and assumptions concerning field life, timing of abandonment activities, cost structures, future labor rates and heavy equipment
rental costs, expected inflation rates and changes in the regulatory environment. ARO estimates must be continually revised to
reflect changes in these factors. Accordingly, we perform a comprehensive review of ARO estimates semi-annually with the
proposed estimates and changes reflected in June 30 and December 31 period-end financial statements.
Effect if Actual Results Differ from Assumptions As of December 31, 2017, our consolidated balance sheet includes ARO
liabilities of $875 million. Changes in the fair value of our ARO balance from prior year included both upward and downward
revisions primarily due to revised timing and scope of remediation work resulting from assessment of abandonment work
performed to-date and current cost experience on retirement obligations in the same operational areas. Future changes in rig
rates, labor rates, inflation and interest rates, timing of settlements, scope of work, technological developments and changes in
the environmental and regulatory climate may result in revisions to our ARO estimates which can be material to our financial
position.
For the year ended December 31, 2017, we recorded $47 million of accretion expense in our consolidated statements of
operations. A 10% increase in our ARO estimate as of December 31, 2017 would have impacted net loss by approximately $4
million. See Item 8. Financial Statements and Supplementary Data - Note 9. Asset Retirement Obligations.
Purchase Price Allocations and Resulting Goodwill
Description We occasionally acquire assets and assume liabilities in transactions accounted for as business combinations, such
as the Clayton Williams Energy Acquisition in 2017 and the Rosetta Merger in 2015. In connection with a purchase business
combination, the acquiring company must allocate the cost of the acquisition to assets acquired and liabilities assumed, based
on fair values as of the acquisition date. Deferred taxes must be recorded for any differences between the assigned values and
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tax bases of assets and liabilities. Any excess of the purchase price over amounts assigned to assets and liabilities is recorded as
goodwill. The amount of goodwill or gain on bargain purchase recorded in any particular business combination can vary
significantly depending upon the values attributed to assets acquired and liabilities assumed.
Goodwill is not amortized to earnings but is assessed, at least annually, for impairment at the reporting unit level. A “reporting
unit” is the level of reporting at which goodwill is tested for impairment. A reporting unit is an operating segment or one level
below an operating segment. Our policy is to conduct a qualitative goodwill impairment assessment by examining relevant
events and circumstances which could have a negative impact on our goodwill, such as: macroeconomic conditions; industry
and market conditions, including commodity prices; cost factors; overall financial performance; reporting unit dispositions and
acquisitions; and other relevant entity-specific events.
If, after assessing the totality of events or circumstances described above, we determine that it is more likely than not that the
fair value of our Texas reporting unit is less than its carrying amount, the two-step goodwill test is performed. The two-step
goodwill impairment test is also performed whenever events or changes in circumstances indicate that the carrying value may
not be recoverable. If, after performing the two-step goodwill test, it is determined that the carrying value of goodwill is
impaired, the amount of goodwill is reduced and a corresponding charge is made to earnings in the period in which the
goodwill is determined to be impaired.
The two-step impairment test is used to identify potential goodwill impairment and measure the amount of a goodwill
impairment loss to be recognized. The first step of the goodwill impairment test, used to identify potential impairment,
compares the fair value of a reporting unit with its carrying amount, including goodwill. If the fair value of the reporting unit
exceeds its carrying amount, goodwill is not considered to be impaired, and the second step of the test is not required. If
necessary, the second step of the impairment test, used to measure the amount of impairment loss, compares the implied fair
value of reporting unit goodwill with the carrying amount of that goodwill. If the carrying amount of reporting unit goodwill
exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess.
Judgment and Uncertainties Preparing a purchase price allocation requires estimating the fair values of assets acquired and
liabilities assumed in a business combination, and we must make various assumptions. The most significant assumptions relate
to the estimated fair values assigned to proved and unproved crude oil and natural gas properties. In most cases, sufficient
market data is not available regarding the fair values of proved and unproved properties, and we prepare estimates of such
properties based on the fair value of associated crude oil, natural gas and NGL reserves utilizing the income approach.
The primary assumptions used to arrive at estimates of future net cash flows are reserves quantities, commodity prices, and
capital and operating costs. For estimated proved reserves, the future net cash flows are discounted using a market-based
weighted average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted average
cost of capital rate is subjected to additional project-specific risking factors. To compensate for the inherent risk of estimating
and valuing unproved reserves, the discounted future net cash flows of probable and possible reserves are reduced by additional
risk-weighting factors.
Estimated deferred taxes are based on available information concerning the tax bases of assets acquired and liabilities assumed
and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information
becomes known.
Resulting goodwill from a purchase price allocation must be assessed for impairment. We perform our annual goodwill
impairment test at the end of the third quarter of each year unless events or circumstances trigger the need for an interim
impairment test.
The first step of the impairment test requires management to make estimates regarding the fair value of the reporting unit to
which goodwill has been assigned. If it is necessary to determine the fair value of the Texas reporting unit, we use a
combination of the income approach and the market approach.
•
Income Approach Under the income approach, the fair value of the Texas reporting unit is estimated based on the
present value of expected future cash flows. The income approach is dependent on a number of factors, including
estimates of forecasted revenue and operating costs and proved reserves, as well as the success of future exploration
for and development of unproved reserves, discount rates and other variables. Negative revisions of estimated reserves
quantities, increases in future cost estimates, divestiture of a significant component of the reporting unit, or sustained
decreases in crude oil or natural gas prices could lead to a reduction in expected future cash flows and possibly an
impairment of all or a portion of goodwill in future periods. Key assumptions used in the discounted cash flow model
described above include estimated quantities of crude oil, natural gas and NGL reserves, including both proved
reserves and risk-adjusted unproved reserves; estimates of market prices considering forward commodity price curves
as of the measurement date; and estimates of operating, administrative and capital costs adjusted for inflation. We
discount the resulting future cash flows using a peer group based weighted average cost of capital.
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• Market Approach Under the market approach, we estimate the fair value of the Texas reporting unit by comparison to
similar businesses whose securities are actively traded in the public market The market approach requires management
to make certain judgments about the selection of comparable companies and/or comparable recent company and asset
transactions and transaction premiums, thereby creating a group of guideline public companies or transactions, or a
peer group, that are engaged in similar operations with comparable risks and returns as our reporting unit.
We use the peer group multiple method for the market approach. Market multiples represent market estimates of fair
value based on selected financial metrics. We use earnings before interest, taxes, DD&A and exploration expense (also
known as EBITDAX) as our financial metric as we believe it more accurately compares companies using successful
efforts and full cost accounting methods, both of which are in our peer group. Determination of fair value under the
income approach and the market approach is subject to a high degree of estimation uncertainty as it requires us to
make assumptions and apply judgment to various parameters that are sensitive to industry, market and economic
conditions. The change in these factors in the future may have a negative impact on estimated future cash flows and
the enterprise value of our reporting unit, which could result in future goodwill impairment.
Effect if Actual Results Differ from Assumptions The resulting estimated fair values assigned to assets acquired and liabilities
assumed in a purchase price allocation can have a significant effect on results of operations in the future. A higher fair value
assigned to a property results in higher DD&A expense, which results in lower net earnings. Fair values are based on estimates
of future commodity prices, reserves quantities, operating expenses and development costs. This increases the likelihood of
impairment if future commodity prices or reserves quantities are lower than those originally used to determine fair value, or if
future operating expenses or development costs are higher than those originally used to determine fair value. Impairment would
have no effect on cash flows, but would result in a decrease in net income for the period in which the impairment is recorded.
See Item 8. Financial Statements and Supplementary Data - Note 3. Clayton Williams Energy Acquisition and Item 8. Financial
Statements and Supplementary Data - Note 4. Acquisitions, Divestitures and Merger.
As of December 31, 2017, our consolidated balance sheet includes goodwill of $1.3 billion, resulting from the Clayton
Williams Energy Acquisition in second quarter 2017. All of our recorded goodwill is assigned to the Texas reporting unit.
We conducted a qualitative and quantitative goodwill impairment assessment as of September 30, 2017 and based on the results
of our goodwill impairment test, we concluded that our goodwill at September 30, 2017 was not impaired as the fair value of
our Texas reporting unit was in excess of its respective net book value, including goodwill. While not required under
Accounting Standards Codification (“ASC”) 350 “Intangibles - Goodwill and Other", we also performed a reconciliation of the
determined enterprise fair value as compared to our total company market capitalization. From this additional analysis, we have
concluded that the determination of the enterprise fair value closely aligns with our market capitalization.
The estimates used in our goodwill impairment test do not constitute forecasts or projections of future results of operations, but
are rather estimates and assumptions based on historical results and assessments of macroeconomic factors affecting the Texas
reporting unit as of the valuation date. We believe that our estimates and assumptions are reasonable, but they are subject to
change from period to period. Actual results of operations and other factors will likely differ from the estimates used in our
discounted cash flow valuation and it is possible that differences could be material. Although we base the fair value estimate of
the Texas reporting unit on assumptions we believe to be reasonable, those assumptions are inherently unpredictable and
uncertain and actual results could differ from the estimate. In the event of a prolonged industry downturn, commodity prices
again become depressed or decline, thereby causing the fair value of the Texas reporting unit to decline, which could result in
an impairment of goodwill.
If, in the future, we dispose of a reporting unit or a portion of a reporting unit that constitutes a business, we will include
goodwill associated with that business in the carrying amount of the business in order to determine the gain or loss on disposal.
The amount of goodwill allocated to the carrying amount of a business can significantly impact the amount of gain or loss
recognized on the sale of that business. The amount of goodwill to be included in that carrying amount will be based on the
relative fair value of the business to be disposed of and the portion of the reporting unit that will be retained. See Item 8.
Financial Statements and Supplementary Data - Note 3. Clayton Williams Energy Acquisition.
Exit Costs
Description We account for exit costs in accordance with ASC 420 - Exit or Disposal Cost Obligations, which requires that a
liability for a cost associated with an exit or disposal activity be recognized at fair value in the period in which the liability is
incurred. Further, a liability for costs that will continue to be incurred under a contract for its remaining term without economic
benefit to the entity shall be recognized at the “cease-use date,” which is defined as the date the entity ceases using the right
conveyed by the contract, for example, the right to use a leased property or to receive future goods or services.
During second quarter 2017, in connection with our Marcellus Shale upstream divestiture, we accrued a liability of $41 million,
discounted, for exit costs related to our commitment under a retained firm transportation contract and charged the amount to
loss on Marcellus Shale upstream divestiture in our consolidated statements of operations.
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In addition, we have retained other Marcellus Shale firm transportation contracts, relating to pipeline projects that either were
recently placed in service in late 2017/early 2018 or are not yet commercially available to us. These projects that are not yet
available will undergo construction and, as these projects become commercially available to us, we will assess, based upon the
facts and circumstances, the recognition of any potential exit cost liabilities. If we determine that we will not utilize a portion,
or all, of the contracted pipeline capacity, we will accrue a liability, at fair value, for the amount of the estimated remaining
financial commitment and include the related expense in operating expense in our consolidated statements of operations.
Any additional exit cost liability will be initially recorded at fair value, and, in periods subsequent to initial measurement,
changes to the liability, including changes resulting from revisions to either the timing or the amount of estimated cash flows
over the future contract period, will be recognized as an adjustment to the liability in the period of the change.
Judgment and Uncertainties We are required to make significant judgments and estimates regarding the timing and amount of
recognition of any additional exit cost liabilities, taking into consideration our commercialization activities and/or the potential
occurrence of a cease-use date. We must consider, among other factors, the following:
•
•
•
•
the status of negotiations with counterparties regarding partial or permanent release of our contract commitments;
the status of FERC approval of prospective pipeline projects;
the timing of commercial availability of approved pipelines upon completion of construction; and
the likelihood of capacity utilization through purchase of third party gas, which would reduce unutilized volume
commitments.
Additionally, any subsequent changes in interest rates and/or credit risk will affect the discount rate used to calculate the
present value of expected future cash flows associated with our existing contract commitments.
There are inherent uncertainties surrounding the recording of exit cost liabilities, and in future periods, a number of factors
could significantly change our estimate of such obligations or result in recognition of additional liability
Effect if Actual Results Differ from Assumptions As of December 31, 2017 our financial commitment associated with
Marcellus Shale firm transportation contracts was approximately $1.4 billion, undiscounted. We are currently engaged in
actions to commercialize and address these remaining commitments, which would reduce our undiscounted financial
commitment. We cannot guarantee our commercialization efforts will be successful, and we may recognize substantial future
liabilities, at fair value, for the net amount of the estimated remaining commitments under these contracts, with the offsetting
charge reducing our earnings. See Item 8. Financial Statements and Supplementary Data - Note 17. Commitments and
Contingencies.
Income Tax Expense and Deferred Tax Assets
Description We are subject to income and other taxes in numerous taxing jurisdictions worldwide. For financial reporting
purposes, we provide taxes at rates applicable for the appropriate tax jurisdictions. Estimates of amounts of income tax to be
recorded involve interpretation of complex tax laws, including the recently enacted Tax Cuts and Jobs Act, as well as
assessment of the effects of foreign taxes on domestic taxes, and estimates regarding the timing and amounts of future
repatriation of earnings from controlled foreign corporations.
Our consolidated balance sheets include deferred tax assets. Deferred tax assets arise when expenses are recognized in the
financial statements before they are recognized in the tax returns or when income items are recognized in the tax returns before
they are recognized in the financial statements. Deferred tax assets also arise when operating losses or tax credits are available
to offset tax payments due in future years. Ultimately, realization of a deferred tax asset depends on the existence of sufficient
taxable income within the future periods to absorb future deductible temporary differences, loss carryforwards or credits.
In assessing the realizability of deferred tax assets, management must consider whether it is more likely than not that some
portion or all of the deferred tax assets will not be realized.
Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is
required. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax
planning strategies in making this assessment, and judgment is required in considering the relative weight of negative and
positive evidence. We continue to monitor facts and circumstances in the reassessment of the likelihood that operating loss
carryforwards, credits and other deferred tax assets will be utilized prior to their expiration. As a result, we may determine, and
we have determined in the past, that a deferred tax asset valuation allowance should be established.
Judgment and Uncertainties In assessing facts and circumstances surrounding realizability of our deferred tax assets we are
required to apply judgment to determine the weight of both positive and negative evidence in order to conclude whether the
valuation allowance is necessary relative to net operating loss carryforwards and other deferred tax assets.
85
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In determining whether a valuation allowance is required for our deferred tax asset balances, we consider, among other factors,
current financial position, results of operations, projected future taxable income, tax planning strategies and new tax legislation.
Significant judgment is involved in this determination as we are required to make assumptions about future commodity prices,
projected production, development activities, profitability of future business strategies and forecasted economics in the oil and
gas industry. Additionally changes in the effective tax rate resulting from changes in tax law and our level of earnings may limit
utilization of deferred tax assets and will affect valuation of deferred tax balances in the future.
Effect if Actual Results Differ from Assumptions As of December 31, 2017, our US federal income tax net operating loss
carryforwards totaled approximately $3.2 billion and foreign net operating loss carryforwards were $662 million. The deferred
tax asset associated with our federal and foreign net operating loss carryforwards was approximately $672 million and $187
million, respectively, classified, net, in our consolidated balance sheet within noncurrent deferred income tax liability balance.
We currently have a valuation allowance on the deferred tax assets associated with foreign loss carryforwards and foreign tax
credits. The valuation allowance on foreign loss carryforwards totaled $183 million in 2017 and $242 million in 2016. The
changes to the valuation allowance for the loss carryforwards between periods was attributable to the offset of the valuation
allowance against the NOL in a jurisdiction in which we are no longer active. Deemed foreign tax credits of $164 million were
recognized along with the additional taxable income associated with the transition tax. A full valuation allowance of $366
million has been recorded against all foreign tax credits based on current interpretation of US Tax Reform law and the expected
future utilization of net operating loss carryforwards. Any increase or decrease in a deferred tax asset valuation allowance
would impact net income through offsetting changes in income tax expense, which could have a negative impact on our
financial position and results of operations. See Item 8. Financial Statements and Supplementary Data - Note 11. Income Taxes.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Derivative Instruments Held for Non-Trading Purposes We are exposed to commodity price risk in the normal course of
business operations. Due to commodity price volatility, we may use derivative instruments as a means of managing our
exposure to price changes.
At December 31, 2017, we had various open commodity derivative instruments related to global crude oil and domestic natural
gas. Changes in fair value of commodity derivative instruments are reported in earnings in the period in which they occur. Our
open commodity derivative instruments were in a net liability position at December 31, 2017 with a fair value of $71 million.
Based on the December 31, 2017 published commodity futures price curves for the underlying commodities, a hypothetical
price increase of 10% per Bbl for crude oil would increase the fair value of our net commodity derivative liability by
approximately $146 million. A hypothetical price increase of 10% per MMBtu for natural gas would increase the fair value of
our net commodity derivative liability by approximately $5 million.
Our derivative instruments are executed under master agreements which allow us to net settle by counterparty. Net settlements
take into account deferred premiums we have agreed to pay for put options. In addition, in the event of default, these master
agreements allow us to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early
termination, all asset and liability positions with the defaulting counterparty would be net cash settled at the time of election.
None of our counterparty agreements contain margin requirements.
Even with certain hedging arrangements in place to mitigate the effect of commodity price volatility, our 2018 revenues and
results of operations could be adversely affected if commodity prices were to decline. See Item 1A. Risk Factors – Commodity
hedging transactions may limit our potential gains or fail to protect us from declines in commodity prices and Item 8. Financial
Statements and Supplementary Data – Note 8. Derivative Instruments and Hedging Activities.
Interest Rate Risk
Changes in interest rates affect the amount of interest we pay on borrowings under our credit facilities and the amount of
interest we earn on our short-term investments.
At December 31, 2017, we had approximately $6.5 billion (excluding capital lease and other obligations) of long-term debt
outstanding. Of this amount, approximately $6.3 billion was fixed-rate debt, with a weighted average interest rate of 5.04% at
December 31, 2017. Although near term changes in interest rates may affect the fair value of our fixed-rate debt, they do not
expose us to the risk of earnings or cash flow loss. See Item 8. Financial Statements and Supplementary Data – Note 10. Long-
Term Debt.
We are also exposed to interest rate risk related to our interest-bearing cash and cash equivalents balances and amounts
outstanding under our credit facilities. As of December 31, 2017, our cash and cash equivalents totaled approximately $675
million, approximately 59% of which was invested in money market funds and short-term investments with major financial
institutions. A change in the interest rate applicable to our short term investments or amounts outstanding under our credit
facilities would have a de minimis impact on our earnings and cash flows. We currently have no interest rate derivative
86
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Index to Financial Statements
instruments outstanding. However, we may enter into interest rate derivative instruments in the future if we determine that it is
necessary to invest in such instruments in order to mitigate our interest rate risk.
Foreign Currency Risk
The US dollar is considered the functional currency for each of our international operations. Substantially all of our
international crude oil, natural gas and NGL production is sold pursuant to US dollar denominated contracts. Transactions, such
as operating costs and administrative expenses that are paid in a foreign currency, are remeasured into US dollars and recorded
in the financial statements at prevailing currency exchange rates. Certain monetary assets and liabilities, for example certain
local working capital items, are denominated in a foreign currency and remeasured into US dollars. A reduction in the value of
the US dollar against currencies of other countries in which we have material operations could result in the use of additional
cash to settle operating, administrative, and tax liabilities. This risk may be mitigated to the extent commodity prices increase in
response to a devaluation of the US dollar.
Net foreign transaction (gains) losses were de minimis for 2017, 2016 and 2015. Foreign transaction (gains) losses are included
in other (income) expense, net in the consolidated statements of operations.
We currently have no foreign currency derivative instruments outstanding. However, we may enter into foreign currency
derivative instruments (such as forward contracts, costless collars or swap agreements) in the future if we determine that it is
necessary to invest in such instruments in order to mitigate our foreign currency exchange risk.
87
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Index to Financial Statements
Item 8. Financial Statements and Supplementary Data
INDEX TO FINANCIAL STATEMENTS
Consolidated Financial Statements of Noble Energy, Inc.
Management’s Report on Internal Control over Financial Reporting....................................................................................
89
Report of Independent Registered Public Accounting Firm (Financial Statements) .............................................................
90
Report of Independent Registered Public Accounting Firm (Internal Control over Financial Reporting) ............................
91
Consolidated Statements of Operations for Each of the Years in the Three-year Period Ended December 31, 2017 ...........
92
Consolidated Statements of Comprehensive Income (Loss) for Each of the Years
93
in the Three-year Period Ended December 31, 2017 .............................................................................................................
Consolidated Balance Sheets as of December 31, 2017 and 2016.........................................................................................
94
Consolidated Statements of Cash Flows for Each of the Years in the Three-year Period Ended December 31, 2017 ..........
95
Consolidated Statements of Shareholders’ Equity for Each of the Years
in the Three-year Period Ended December 31, 2017 .............................................................................................................
96
Notes to Consolidated Financial Statements
Note 1. Summary of Significant Accounting Policies .........................................................................................................
Note 2. Additional Financial Statement Information...........................................................................................................
Note 3. Clayton Williams Energy Acquisition.....................................................................................................................
Note 4. Acquisitions, Divestitures, and Merger ...................................................................................................................
Note 5. Asset Impairments...................................................................................................................................................
Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs...............................................................
Note 7. Equity Method Investments ....................................................................................................................................
Note 8. Derivative Instruments and Hedging Activities ......................................................................................................
Note 9. Asset Retirement Obligations..................................................................................................................................
Note 10. Long-Term Debt....................................................................................................................................................
Note 11. Income Taxes.........................................................................................................................................................
Note 12. Stock-Based and Other Compensation Plans........................................................................................................
Note 13. Fair Value Measurements and Disclosures ...........................................................................................................
Note 14. Segment Information.............................................................................................................................................
Note 15. Concentration of Risk ...........................................................................................................................................
Note 16. Additional Shareholders' Equity Information .......................................................................................................
Note 17. Commitments and Contingencies .........................................................................................................................
97
105
107
109
112
113
115
116
119
120
122
126
130
132
135
136
137
Supplemental Oil and Gas Information (Unaudited) .............................................................................................................
139
Supplemental Quarterly Financial Information (Unaudited) .................................................................................................
152
88
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Index to Financial Statements
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal
control over financial reporting is a process designed under the supervision of our Chief Executive Officer and Chief Financial
Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated
financial statements for external purposes in accordance with accounting principles generally accepted in the United States of
America.
Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements.
Projections of any evaluation of the effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or processes may deteriorate.
As of December 31, 2017, our management assessed the effectiveness of our internal control over financial reporting based on
the criteria for effective internal control over financial reporting established in Internal Control – Integrated Framework
(2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment,
management determined that we maintained effective internal control over financial reporting as of December 31, 2017, based
on those criteria.
KPMG LLP, the independent registered public accounting firm that audited our consolidated financial statements included in
this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of internal control over financial
reporting as of December 31, 2017 which is included herein.
Noble Energy, Inc.
89
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Index to Financial Statements
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders
Noble Energy, Inc.:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Noble Energy, Inc. and subsidiaries (the “Company”) as of
December 31, 2017 and 2016, the related consolidated statements of operations, comprehensive income (loss), shareholders’
equity, and cash flows for each of the years in the three-year period ended December 31, 2017, and the related notes
(collectively, the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all
material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations
and its cash flows for each of the years in the three-year period ended December 31, 2017, in conformity with U.S. generally
accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in
Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission, and our report dated February 20, 2018 expressed an unqualified opinion on the effectiveness of the Company’s
internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express
an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the
PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws
and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement,
whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the
consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such
procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial
statements. Our audits also included evaluating the accounting principles used and significant estimates made by management,
as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a
reasonable basis for our opinion.
/s/ KPMG LLP
We have served as the Company’s auditor since 2002.
Houston, Texas
February 20, 2018
90
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Index to Financial Statements
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders
Noble Energy, Inc.:
Opinion on Internal Control Over Financial Reporting
We have audited Noble Energy, Inc.’s and subsidiaries’ (the “Company”) internal control over financial reporting as of
December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee
of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects,
effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control -
Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(“PCAOB”), the consolidated balance sheets of the Company as of December 31, 2017 and 2016, the related consolidated
statements of operations, comprehensive income (loss), shareholders’ equity, and cash flows for each of the years in the three-
year period ended December 31, 2017, and the related notes (collectively, the “consolidated financial statements”), and our
report dated February 20, 2018 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting, included in the accompanying management’s report
on internal controls over financial reporting. Our responsibility is to express an opinion on the Company’s internal control over
financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be
independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and
regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all
material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control
over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we
considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures
that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Houston, Texas
February 20, 2018
/s/ KPMG LLP
91
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Index to Financial Statements
Noble Energy, Inc.
Consolidated Statements of Operations
(millions, except per share amounts)
Year Ended December 31,
2017
2016
2015
$
4,060
$
3,389
$
196
4,256
1,141
188
2,053
415
2,379
70
—
(188)
6,058
(1,802)
(63)
98
354
—
102
3,491
1,100
925
2,454
399
—
92
—
(103)
4,867
(1,376)
139
(80)
328
9
389
(2,191)
(1,141)
(1,050)
68
(1,118) $
396
(1,772)
(787)
(985)
13
(998) $
3,093
90
3,183
996
488
2,131
396
—
533
779
332
5,655
(2,472)
(501)
—
263
(15)
(253)
(2,219)
222
(2,441)
—
(2,441)
(2.38) $
(2.32) $
(6.07)
469
430
402
Revenues
Oil, Gas and NGL Sales
Income from Equity Method Investees and Other
Total Revenues
Costs and Expenses
Production Expense
Exploration Expense
Depreciation, Depletion and Amortization
General and Administrative
Loss on Marcellus Shale Upstream Divestiture
Asset Impairments
Goodwill Impairment
Other Operating (Income) Expense, Net
Total Operating Expenses
Operating Loss
Other Expense (Income)
(Gain) Loss on Commodity Derivative Instruments
Loss (Gain) on Extinguishment of Debt
Interest, Net of Amount Capitalized
Other Non-Operating Expense (Income), Net
Total Other Expense (Income)
Loss Before Income Taxes
Income Tax (Benefit) Provision
Net Loss Including Noncontrolling Interests
Less: Net Income Attributable to Noncontrolling Interests
Net Loss Attributable to Noble Energy
Net Loss Attributable to Noble Energy per Share of Common Stock
Basic and Diluted
Weighted Average Number of Shares Outstanding
Basic and Diluted
$
$
The accompanying notes are an integral part of these financial statements.
92
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Index to Financial Statements
Noble Energy, Inc.
Consolidated Statements of Comprehensive Income (Loss)
(millions)
Year Ended December 31,
2017
2016
2015
$
(1,050) $
(985) $
(2,441)
—
—
3
(1)
2
(1,048) $
68
(1,116) $
—
—
3
(1)
2
(983) $
13
(996) $
(11)
4
99
(35)
57
(2,384)
—
(2,384)
Net Loss Including Noncontrolling Interests
Other Items of Comprehensive Loss
Net Change in Mutual Fund Investment
Less Tax Expense
Net Change in Pension and Other
Less Tax Benefit
Other Comprehensive Income
Comprehensive Loss Including Noncontrolling Interests
Less: Comprehensive Income Attributable to Noncontrolling Interests
Comprehensive Loss Attributable to Noble Energy
$
$
The accompanying notes are an integral part of these financial statements.
93
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Index to Financial Statements
Noble Energy, Inc.
Consolidated Balance Sheets
(millions)
ASSETS
Current Assets
Cash and Cash Equivalents
Accounts Receivable, Net
Other Current Assets
Total Current Assets
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method of Accounting)
Property, Plant and Equipment, Other
Total Property, Plant and Equipment, Gross
Accumulated Depreciation, Depletion and Amortization
Total Property, Plant and Equipment, Net
Goodwill
Other Noncurrent Assets
Total Assets
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts Payable - Trade
Other Current Liabilities
Total Current Liabilities
Long-Term Debt
Net Deferred Income Tax Liability
Other Noncurrent Liabilities
Total Liabilities
Shareholders’ Equity
Preferred Stock - Par Value $1.00 per share; 4 Million Shares Authorized, None Issued
Common Stock - Par Value $0.01; 1 Billion Shares Authorized; 529 Million and 471
Million Shares Issued, Respectively
Additional Paid in Capital
Accumulated Other Comprehensive Loss
Treasury Stock, at Cost; 39 Million and 38 Million Shares, Respectively
Retained Earnings
Noble Energy Share of Equity
Noncontrolling Interests
Total Equity
Total Liabilities and Equity
The accompanying notes are an integral part of these financial statements.
94
December 31,
2017
December 31,
2016
$
$
$
$
675
748
780
2,203
29,678
879
30,557
(13,055)
17,502
1,310
461
1,180
615
160
1,955
30,355
909
31,264
(12,716)
18,548
—
508
21,476
$
21,011
1,161
$
578
1,739
6,746
1,127
1,245
736
742
1,478
7,011
1,819
1,103
10,857
11,411
—
5
8,438
(30)
(725)
2,248
9,936
683
10,619
$
21,476
$
—
5
6,450
(31)
(692)
3,556
9,288
312
9,600
21,011
Table of Contents
Index to Financial Statements
Noble Energy, Inc.
Consolidated Statements of Cash Flows
(millions)
Cash Flows From Operating Activities
Net Loss Including Noncontrolling Interests
Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities
$ (1,050) $
(985) $ (2,441)
Year Ended December 31,
2017
2016
2015
Depreciation, Depletion and Amortization
Asset Impairments
Loss on Marcellus Shale Upstream Divestiture
Goodwill Impairment
Dry Hole Cost
Deferred Income Taxes
(Gain) Loss on Commodity Derivative Instruments
Net Cash Received in Settlement of Commodity Derivative Instruments
Gain on Divestitures
Stock Based Compensation
Non-cash Pension Plan Termination Expense
Loss (Gain) on Debt Extinguishment
Undeveloped Leasehold Impairment
Expiration and Amortization of Undeveloped Leaseholds
Other Adjustments for Noncash Items Included in Income
Changes in Operating Assets and Liabilities, Net of Assets Acquired and Liabilities Assumed
(Increase) Decrease in Accounts Receivable
Increase (Decrease) in Accounts Payable
(Decrease) Increase in Current Income Taxes Payable
(Decrease) Increase in Other Current Liabilities
Other Operating Assets and Liabilities, Net
Net Cash Provided by Operating Activities
Cash Flows From Investing Activities
Additions to Property, Plant and Equipment
Proceeds from Divestitures
Clayton Williams Energy Acquisition, Net of Cash Received
Other Acquisitions
Marcellus Shale Acreage Exchange Consideration
Other
Net Cash Used in Investing Activities
Cash Flows From Financing Activities
Dividends Paid, Common Stock
Proceeds from Issuance of Noble Energy Common Stock, Net of Offering Costs
Proceeds from Revolving Credit Facility
Repayment of Revolving Credit Facility
Repayment of Clayton Williams Energy Long-term Debt
Proceeds from Term Loan Facility
Repayment of Term Loan Facility
Proceeds from Issuance of Senior Notes, Net
Repayment of Senior Notes
Proceeds from Noble Midstream Services Revolving Credit Facility
Repayment of Noble Midstream Services Revolving Credit Facility
Proceeds from Issuance of Noble Midstream Partners Common Units, Net of Offering Costs
Other
Net Cash (Used in) Provided By Financing Activities
(Decrease) Increase in Cash and Cash Equivalents
Cash and Cash Equivalents at Beginning of Period
Cash and Cash Equivalents at End of Period
The accompanying notes are an integral part of these financial statements.
95
2,053
70
2,379
—
9
(1,227)
(63)
13
(326)
104
—
98
62
—
(21)
(171)
248
(36)
(101)
(90)
1,951
(2,649)
2,073
(616)
(327)
—
(87)
(1,606)
(190)
—
1,585
(1,355)
(595)
—
(550)
1,086
(1,114)
325
(240)
312
(114)
(850)
(505)
1,180
675
$
2,454
92
—
—
579
(984)
139
569
(238)
77
—
(80)
93
55
40
(164)
(111)
(32)
(63)
(90)
1,351
2,131
533
—
779
266
116
(501)
1,009
—
86
82
—
21
92
18
453
(364)
(94)
(70)
(54)
2,062
(1,541)
1,241
—
—
(213)
82
(431)
(172)
—
—
—
—
1,400
(850)
—
(1,383)
—
—
299
(62)
(768)
152
1,028
$ 1,180
(2,979)
151
—
—
—
(43)
(2,871)
(291)
1,112
—
(70)
—
—
—
—
(12)
—
—
—
(85)
654
(155)
1,183
$ 1,028
Table of Contents
Index to Financial Statements
Noble Energy, Inc.
Consolidated Statements of Shareholders' Equity
(millions)
Attributable to Noble Energy
Common
Stock
Additional
Paid in
Capital
Accumulated
Other
Comprehensive
Loss
Treasury
Stock at
Cost
Retained
Earnings
Non-
controlling
Interests
Total
Equity
December 31, 2014
$
Net Loss
Rosetta Merger
Stock-based Compensation
Exercise of Stock Options
Dividends (72 cents per share)
Issuance of Shares of Noble
Energy Common Stock to
Public, Net of Offering Costs
Net Change in Other
December 31, 2015
Net (Loss) Income
Stock-based Compensation
Exercise of Stock Options
Dividends (40 cents per share)
Issuance of Noble Midstream
Partners Common Units, Net of
Offering Costs
Net Change in Other
December 31, 2016
Net (Loss) Income
Clayton Williams Energy
Acquisition
Stock-based Compensation
Exercise of Stock Options
Dividends (40 cents per share)
Issuance of Noble Midstream
Partners Common Units, Net of
Offering Costs
Distributions to Noncontrolling
Interest Owners
Net Change in Other
December 31, 2017
$
$
$
4
—
1
—
—
—
—
—
5
—
—
—
—
—
—
5
—
—
—
—
—
—
—
—
5
$
3,624
$
—
1,528
86
8
—
1,112
2
6,360
$
$
—
68
24
—
—
(2)
$
6,450
$
—
1,876
100
10
—
—
—
2
$
8,438
$
(90) $
—
(671) $
—
7,458
(2,441)
—
—
—
(291)
—
—
4,726
(998)
—
—
(172)
—
—
—
—
—
(17)
(688) $
—
—
—
—
—
(4)
(692) $
—
—
—
3,556
(1,118)
(25)
—
—
—
—
—
(8)
(725) $
—
—
—
(190)
—
—
—
—
—
—
—
—
57
(33) $
—
—
—
—
—
2
(31) $
—
—
—
—
—
—
—
1
(30) $
— $ 10,325
— (2,441)
1,529
—
—
—
—
86
8
(291)
—
1,112
42
—
— $ 10,370
(985)
68
13
—
—
—
299
—
312
68
—
—
—
—
24
(172)
299
(4)
$ 9,600
(1,050)
1,851
100
10
(190)
312
312
(28)
19
(28)
14
2,248
683
$ 10,619
The accompanying notes are an integral part of these financial statements.
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Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 1. Summary of Significant Accounting Policies
General Noble Energy, Inc. (Noble Energy, we or us) is a leading independent energy company engaged in worldwide crude
oil and natural gas exploration and production. Our historical operating areas include: US onshore, primarily the DJ Basin,
Delaware Basin, Eagle Ford Shale and Marcellus Shale (until June 2017); US offshore Gulf of Mexico; Eastern Mediterranean;
and West Africa. Our Midstream segment owns, operates, develops and acquires domestic midstream infrastructure assets with
current focus areas being the DJ and Delaware Basins.
Basis of Presentation and Consolidation Accounting policies used by us and our subsidiaries conform to US GAAP.
Significant policies are discussed below. Our consolidated accounts include our accounts and the accounts of our wholly-owned
subsidiaries. All significant intercompany balances and transactions have been eliminated upon consolidation.
Equity Method of Accounting We use the equity method of accounting for investments in entities that we do not control but
over which we exert significant influence. Our equity investees own and operate various midstream assets which we consider
an essential component of our business and a necessary and integral element to our value chain involving the monetization of
natural gas. With our partners, we engage in joint strategic operational and financial decision making for these entities.
In order to reflect the economics associated with our integrated upstream value chain described above, we include income from
equity method investees as a component of revenues in our consolidated statements of operations.
We carry equity method investments at our share of net assets of the equity investees plus loans and advances, and include the
investments in other noncurrent assets in our consolidated balance sheets. Within our consolidated statements of cash flows,
activity is reflected within cash flows provided by operating activities and cash flows provided by (used in) investing activities.
Differences in the basis of the investment and the separate net asset value of the investee, if any, are amortized into income over
the remaining useful life of the underlying assets. Our share of income taxes incurred directly by the equity method investees is
reported in income from equity method investees and is not included in our income tax provision in our consolidated statements
of operations. See Note 7. Equity Method Investments.
Noncontrolling Interests In third quarter 2016, Noble Midstream Partners LP (Noble Midstream Partners), a subsidiary of
Noble Energy, completed its initial public offering of common units. As a result, we present our consolidated financial
statements with a noncontrolling interest section representing the public's ownership in Noble Midstream Partners. See Note 16.
Additional Shareholders' Equity Information.
Consolidated VIE Noble Energy has determined that the partners with equity at risk in Noble Midstream Partners lack the
authority, through voting rights or similar rights, to direct the activities that most significantly impact Noble Midstream
Partners' economic performance; therefore, Noble Midstream Partners is considered a variable interest entity (VIE). Through
Noble Energy's ownership interest in Noble Midstream GP LLC (the General Partner to Noble Midstream Partners), Noble
Energy has the authority to direct the activities that most significantly affect economic performance and the obligation to absorb
losses or the right to receive benefits that could be potentially significant to Noble Midstream Partners. Therefore, Noble
Energy is considered the primary beneficiary and consolidates Noble Midstream Partners.
Use of Estimates The preparation of consolidated financial statements in conformity with US GAAP requires us to make a
number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent
assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses
during the reporting period.
Estimated quantities of crude oil, natural gas and NGL reserves are the most significant of our estimates. All the reserves data
included in this Annual Report Form 10-K are estimates. Reservoir engineering is a subjective process of estimating
underground accumulations of crude oil, natural gas and NGLs. There are numerous uncertainties inherent in estimating
quantities of proved crude oil, natural gas and NGL reserves. The accuracy of any reserves estimate is a function of the quality
of available data and of engineering and geological interpretation and judgment. As a result, reserves estimates may be different
from the quantities of crude oil, natural gas and NGLs that are ultimately recovered. Qualified petroleum engineers in our
Houston and Denver offices prepare all reserves estimates for our different geographical regions. These reserves estimates are
reviewed and approved by senior engineering staff and division management with final approval by the Senior Vice President –
Corporate Development and certain members of senior management. See Supplemental Oil and Gas Information (Unaudited).
Other items subject to estimates and assumptions include the carrying amounts of inventory, property, plant and equipment,
goodwill, exit costs and asset retirement obligations (AROs), valuation allowances for receivables and deferred income tax
assets, and valuation of derivative instruments, among others. Management evaluates estimates and assumptions on an ongoing
basis using historical experience and other factors, including the current economic and commodity price environment.
The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. Declines in
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Notes to Consolidated Financial Statements
commodity prices could result in a reduction in our fair value estimates and cause us to perform analyses to determine if our oil
and gas properties are impaired. As future commodity prices cannot be determined accurately, actual results could differ
significantly from our estimates. See Supplemental Oil and Gas Information (Unaudited).
Reclassifications
In Note 14. Segment Information, we report a new Midstream segment, established second quarter 2017, and present prior period
amounts on a comparable basis. Certain other prior-period amounts have been reclassified to conform to the current period
presentation.
Fair Value Measurements Fair value measurements are based on a hierarchy which prioritizes the inputs to valuation techniques
used to measure fair value into three levels. The fair value hierarchy is as follows:
• Level 1 measurements are fair value measurements which use quoted market prices (unadjusted) in active markets for
identical assets or liabilities.
• Level 2 measurements are fair value measurements which use inputs, other than quoted prices included within Level 1,
which are observable for the asset or liability, either directly or indirectly.
• Level 3 measurements are fair value measurements which use unobservable inputs.
The fair value hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements.
We use Level 1 inputs when available, as Level 1 inputs generally provide the most reliable evidence of fair value. See Note 13.
Fair Value Measurements and Disclosures.
Cash and Cash Equivalents For purposes of reporting cash flows, cash and cash equivalents include unrestricted cash on
hand and investments with original maturities of three months or less at the time of purchase.
Allowance for Doubtful Accounts We routinely assess the recoverability of all material trade and other receivables to
determine their collectibility. We accrue a reserve on a receivable when, based on management’s judgment, it is probable that a
receivable will not be collected and the amount of such reserve may be reasonably estimated.
Inventories Inventories consist primarily of tubular goods and production equipment used in our oil and gas operations, and
crude oil produced but not yet sold. Materials and supplies inventories are stated at the lower of cost or net realizable value. The
cost of crude oil inventory includes production costs and DD&A of oil and gas properties. See Note 2. Additional Financial
Statement Information.
Property, Plant and Equipment Significant accounting policies for our property, plant and equipment are as follows:
Successful Efforts Method We account for crude oil and natural gas properties under the successful efforts method of
accounting. Under this method, costs to acquire mineral interests in crude oil and natural gas properties, drill and equip
exploratory wells that find proved reserves, and drill and equip development wells are capitalized. Capitalized costs of
producing crude oil and natural gas properties, along with support equipment and facilities, are amortized to expense by the
unit-of-production method based on proved crude oil, natural gas and NGL reserves on a field-by-field basis, as estimated by
our qualified petroleum engineers. Our policy is to use quarter-end reserves and add back current period production to compute
quarterly DD&A expense. Costs of certain gathering facilities or processing plants serving a number of properties or used for
third-party processing are depreciated using the straight-line method over the useful lives of the assets ranging from three to
thirty years. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are
eliminated from the accounts and the resulting gain or loss is recognized. Costs related to repair and maintenance activities are
expensed as incurred.
Property Impairment For our proved properties, we routinely assess whether impairment indicators arise during any given
quarter and have processes in place to ensure that we become aware of such indicators. Impairment indicators include, but are
not limited to, sustained decreases in commodity prices, negative revisions of proved reserves, and increases in development or
operating costs. In the event that impairment indicators exist, we conduct an impairment test. To that end, we estimate future net
cash flows expected in connection with the property and compare such future net cash flows to the carrying amount of the
property to determine if the carrying amount is recoverable.
When the carrying amount of a property exceeds its estimated undiscounted future net cash flows, the carrying amount is
reduced to estimated fair value. Fair value may be estimated using comparable market data, a discounted cash flow method, or a
combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s
expectations for the future and include estimates of future crude oil and natural gas production, commodity prices based on
published forward commodity price curves or contract prices as of the date of the estimate, operating and development costs,
and a risk-adjusted discount rate.
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Other long-lived assets, such as our midstream assets, are evaluated for potential impairment whenever events or changes in
circumstances indicate that their carrying value may be greater than the undiscounted future net cash flows. Impairment, if any,
is measured as the excess of an asset’s carrying amount over its estimated fair value, which is estimated as described above.
We recorded property impairment charges in 2017, 2016 and 2015 and it is possible that other proved oil and gas properties
could become impaired in the future due to commodity price declines and/or field performance. See Note 5. Asset
Impairments.
Unproved Property Impairment Our unproved properties consist of leasehold costs and allocated value to probable and
possible reserves resulting from acquisitions. We assess individually significant unproved properties for impairment on a
quarterly basis and recognize a loss at the time of impairment by providing an impairment allowance. In determining whether a
significant unproved property is impaired we consider numerous factors including, but not limited to, current exploration plans,
favorable or unfavorable exploration activity on the property being evaluated and/or adjacent properties, our geologists'
evaluation of the property, and the remaining months in the lease term for the property.
When we have allocated fair value to an unproved property as the result of a transaction accounted for as a business
combination, we use a future cash flow analysis to assess the unproved property for impairment. Cash flows used in the
impairment analysis are determined based on management’s estimates of crude oil, natural gas and NGL reserves, future
commodity prices and future costs to produce the reserves. Cash flow estimates related to probable and possible reserves are
reduced by additional risk-weighting factors. Other individually insignificant unproved properties are amortized on a composite
method over an average holding period.
We recorded undeveloped leasehold impairment expense in 2017. It is possible that unproved oil and gas properties, including
undeveloped leases, could become impaired in the future if commodity prices decline or if there are changes in exploration
plans or the timing and extent of development activities. See Note 6. Capitalized Exploratory Well Costs and Undeveloped
Leasehold Costs.
Properties Acquired in Business Combinations When sufficient market data is not available, we determine the fair values of
proved and unproved properties acquired in transactions accounted for as business combinations by preparing our own
estimates of cash flows from the production of crude oil, natural gas and NGL reserves. We estimate future prices to apply to
the estimated reserves quantities acquired, and estimate future operating and development costs, to arrive at estimates of future
net cash flows. For the fair value assigned to proved reserves, future net cash flows are discounted using a market-based
weighted average cost of capital rate determined appropriate at the time of the business combination. To compensate for the
inherent risk of estimating and valuing unproved reserves, discounted future net cash flows of probable and possible reserves
are reduced by additional risk-weighting factors.
Assets Held for Sale We occasionally market oil and gas properties for sale. At the end of each reporting period, we evaluate
properties being marketed to determine whether any should be reclassified as held for sale. The held-for-sale criteria include: a
commitment to a plan to sell; the asset is available for immediate sale; an active program to locate a buyer exists; the sale of the
asset is probable and expected to be completed within one year; the asset is being actively marketed for sale; and it is unlikely
that significant changes to the plan will be made. If each of these criteria is met, the property is reclassified as held for sale in
our consolidated balance sheets and will be valued at the lower of net book value or anticipated sales proceeds less costs to sell.
Impairment expense would be recorded for any excess of net book value over anticipated sales proceeds less costs to sell. See
Note 4. Acquisitions, Divestitures and Merger.
Exploration Costs Geological and geophysical costs, delay rentals, amortization of unproved leasehold costs, and costs to drill
exploratory wells that do not find proved reserves are expensed as oil and gas exploration. We carry the costs of an exploratory
well as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as
we are making sufficient progress assessing the reserves and the economic and operating viability of the project. For certain
capital-intensive Gulf of Mexico or international projects, it may take us more than one year to evaluate the future potential of
the exploratory well and make a determination of its economic viability. Our ability to move forward on a project may be
dependent on gaining access to transportation or processing facilities or obtaining permits and government or partner approval,
the timing of which is beyond our control. In such cases, exploratory well costs remain suspended as long as we are actively
pursuing access to necessary facilities and access to such permits and approvals and believe they will be obtained. We assess
the status of suspended exploratory well costs on a quarterly basis. See Note 6. Capitalized Exploratory Well Costs and
Undeveloped Leasehold Costs.
Other Property Other property includes automobiles, trucks, airplanes, office furniture, computer equipment and other fixed
assets such as buildings and leasehold improvements. These items are recorded at cost and are depreciated on the straight-line
method based on expected lives of the individual assets or group of assets, which range from three to thirty years. Other
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property also includes linefill, which is recorded at cost to produce into the production line. Linefill is not subject to
depreciation but is reviewed for impairment.
Capitalization of Interest We capitalize interest costs associated with the development and construction of significant
properties or projects to bring them to a condition and location necessary for their intended use, which for crude oil and natural
gas assets is at first production from the field. Interest is capitalized using an interest rate equivalent to the weighted average
rate we pay on long-term debt, including our unsecured revolving credit facility (Revolving Credit Facility) and bonds.
Capitalized interest is included in the cost of oil and gas assets and amortized with other costs on a unit-of-production basis.
Capitalized interest totaled $49 million in 2017, $84 million in 2016, and $144 million in 2015.
Asset Retirement Obligations AROs consist of estimated costs of dismantlement, removal, site reclamation and similar
activities associated with our oil and gas properties. We recognize the fair value of a liability for an ARO in the period in which
it is incurred when we have an existing legal obligation associated with the retirement of our oil and gas properties that can
reasonably be estimated, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas
asset. The asset retirement cost is recorded at estimated fair value, measured by reference to the expected future cash outflows
required to satisfy the retirement obligation discounted at our credit-adjusted risk-free rate. After initial recording, the liability is
increased for the passage of time, with the increase being reflected as accretion expense and included in DD&A expense in the
consolidated statements of operations. Subsequent adjustments in the cost estimate are reflected in the liability, and the amounts
continue to be amortized over the useful life of the related long-lived asset. See Note 9. Asset Retirement Obligations.
Goodwill
2017 Goodwill As of December 31, 2017, our consolidated balance sheet includes goodwill of $1.3 billion. This goodwill
resulted from the acquisition (Clayton Williams Energy Acquisition) of Clayton Williams Energy, Inc. (Clayton Williams
Energy) completed on April 24, 2017, and represents the excess of the consideration paid for Clayton Williams Energy over the
net amounts assigned to identifiable assets acquired and liabilities assumed. All of our recorded goodwill is assigned to the
Texas reporting unit, a component of our US reportable and operating segment. See Note 3. Clayton Williams Energy
Acquisition.
Goodwill is not amortized to earnings but is qualitatively assessed for impairment. We assess goodwill for impairment annually
during the third quarter, or more frequently as circumstances require, at the reporting unit level. If, based on our qualitative
procedures, it is more likely than not that the fair value of the reporting unit is less than its carrying amount, we perform the
two-step goodwill impairment test. The two-step goodwill impairment test is also performed whenever events or changes in
circumstances indicate that the carrying value may not be recoverable. It is possible that goodwill could become impaired in the
future if commodity prices or other economic factors decline. See Recently Issued Accounting Standards – Intangibles –
Goodwill and Other: Simplifying the Test for Goodwill Impairment, below, for recently issued accounting guidance regarding
future goodwill impairment testing.
We conducted a qualitative goodwill impairment assessment as of September 30, 2017 by examining relevant events and
circumstances which could have a negative impact on our goodwill such as: macroeconomic conditions as pertinent to current
and expected regulations, industry and market conditions, including overall global and regional supply and demand and impact
of such on commodity prices; as well as microeconomic factors relevant to the enterprise such as cost factors that have a
negative effect on earnings and cash flows, overall financial performance, reporting unit dispositions, acquisitions, portfolio
restructuring and other decisions / circumstances specific to the entity and the reporting unit containing goodwill.
Certain negative indicators as of September 30 2017 included the current onshore service cost inflation resulting in pressure on
operating margins impacting our financial results associated with the Texas reporting unit and our stock price. However, we in
turn also noted positive indicators such as the current commodity price environment, our current and future drilling and
development plans for the Texas assets and synergies we expect from the Clayton Williams Energy Acquisition driven by our
unconventional expertise and position in the adjacent properties, which further increase opportunities to drill longer lateral
wells on our combined acreage positions, which would contribute to profitability.
Furthermore, we see value creation to be derived from expected midstream build-out opportunities for the gathering, processing
and servicing of future production in the Delaware Basin. Having assessed the totality of such events and circumstances
described above, we determined that, while there existed certain negative factors, the overall qualitative assessment did not
indicate that it is more likely than not that the fair value of the reporting unit is less than its carrying value. However, regardless
of the outcome of the qualitative review, we decided to proceed with Step 1 of the impairment test as part of our annual review.
As such, we performed Step 1 of the goodwill impairment test, used to identify potential impairment. The result of the Step 1
test indicated that the fair value of the Texas reporting unit exceeded its carrying value, including goodwill, and therefore, the
Texas reporting unit goodwill was not considered to be impaired as of September 30, 2017.
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Notes to Consolidated Financial Statements
If, in the future, we dispose of a reporting unit or a portion of a reporting unit that constitutes a business, we will include
goodwill associated with that business in the carrying amount of the business in order to determine the gain or loss on disposal.
The amount of goodwill allocated to the carrying amount of a business can significantly impact the amount of gain or loss
recognized on the sale of that business. The amount of goodwill to be included in that carrying amount will be based on the
relative fair value of the business to be disposed of and the portion of the reporting unit that will be retained.
2015 Goodwill At December 31, 2015, we reviewed our goodwill balance of $779 million for impairment in accordance with
our accounting policy and identified factors, including continuing declines in commodity prices and the market value of our
common stock, indicating that the fair value of goodwill could have fallen below its book value. We determined that the
goodwill was fully impaired and recognized a loss of $779 million. This goodwill related primarily to the excess purchase price
over amounts assigned to assets acquired and liabilities assumed in the merger of Rosetta Resources Inc. (Rosetta) into a
subsidiary of Noble Energy (Rosetta Merger) in 2015 and the Patina Merger in 2005 and was associated with our US reporting
unit. During 2015, prior to the impairment, goodwill increased $163 million due to the Rosetta Merger and decreased $4
million due to allocations of goodwill to US onshore properties sold.
For purposes of determining the 2015 goodwill impairment, we estimated the implied fair value of the goodwill using a variety
of valuation methods, including the income and market approaches. Our estimate of fair value required us to use significant
unobservable inputs, representative of a Level 3 fair value measurement, including assumptions for future crude oil and natural
gas production, commodity prices based on forward commodity price curves, operating and development costs and other
factors. The analysis supported that the implied fair value of goodwill was zero and, as such, goodwill was fully impaired.
Exit Costs We recognize the fair value of a liability for an exit cost in the period in which a liability is incurred. Accrued exit
costs at December 31, 2017 relate primarily to estimated costs associated with retained Marcellus Shale firm transportation
contracts.
The recognition and fair value estimation of an exit cost liability require that management take into account certain estimates
and assumptions such as: the determination of whether a cease-use date has occurred (defined as the date the entity ceases using
the right conveyed by the contract, for example, the right to use a leased property or to receive future goods or services); the
amount, if any, of economic benefit that is expected to be obtained from a contract through partial use or release; and our
estimate of costs that will continue to be incurred under the contract. We record the liability at estimated fair value, based on
expected future cash outflows required to satisfy the obligation, net of estimated recoveries, and discounted. Exit costs, and
associated accretion expense, are included in operating expense in our consolidated statements of operations. See Note 17.
Commitments and Contingencies.
Derivative Instruments and Hedging Activities All derivative instruments (including certain derivative instruments
embedded in other contracts) are recorded in our consolidated balance sheets as either an asset or liability and measured at fair
value. We account for our commodity derivative instruments using mark-to-market accounting and recognize all gains and
losses in earnings during the period in which they occur. Our consolidated statements of cash flows include the non-cash
portion of gain and loss on commodity derivative instruments, which represents the difference between the total gain and loss
on commodity derivative instruments and the cash received or paid on settlements of commodity derivative instruments during
the period.
We offset the fair value amounts recognized for derivative instruments and the fair value amounts recognized for the right to
reclaim cash collateral or the obligation to return cash collateral. The cash collateral (commonly referred to as a “margin”) must
arise from derivative instruments recognized at fair value that are executed with the same counterparty under a master
agreement with netting clauses.
Stock-Based Compensation Restricted stock and stock options issued to employees and directors are recorded at grant-date
fair value. Expense is recognized on a straight-line basis over the employee’s and director’s requisite service period (generally
the vesting period of the award) in the consolidated statements of operations. In 2016, we issued cash-settled awards to certain
employees in lieu of a portion of restricted stock and stock options. We recognize the value of cash-settled awards utilizing the
liability method as defined under Accounting Standards Codification Topic 718, Compensation – Stock Compensation. The fair
value of liability awards is remeasured at each reporting date, based on the fair market value of a share of common stock of the
Company as of the reporting date, through the settlement date with the change in fair value recognized as compensation
expense over that period. See Note 12. Stock-Based and Other Compensation Plans.
Pension and Other Postretirement Benefit Plans We recognize the funded status (the difference between the fair value of
plan assets and the projected benefit obligation) of restoration and other postretirement benefit plans in the consolidated balance
sheets, with a corresponding adjustment to accumulated other comprehensive loss (AOCL), net of tax. The amount remaining
in AOCL at December 31, 2017 represents unrecognized net actuarial loss and unrecognized prior service cost related to our
restoration plan. These amounts are currently being recognized as net periodic benefit cost pursuant to our historical accounting
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policy for amortizing such amounts. Any actuarial gains and losses that arise during the plan year, but which are not required to
be recognized as net periodic benefit cost in the same period, are recognized as a component of AOCL. In third quarter 2015,
we completed the process of terminating our noncontributory, tax-qualified defined benefit pension plan through the purchase
of annuities for the remaining participants. As a result, we reclassified all remaining unamortized prior service cost and
actuarial losses relating to the pension plan from AOCL to earnings.
Income Taxes and Impact of Tax Reform Legislation Income taxes are accounted for under the asset and liability method.
Deferred tax assets and liabilities are recognized when items of income and expense are recognized in the financial statements
in different periods than when recognized in the applicable tax return. Deferred tax assets arise when expenses are recognized in
the financial statements before the tax return or when income items are recognized in the tax return prior to the financial
statements. Deferred tax assets also arise when operating losses or tax credits are available to offset tax payments due in future
years. Deferred tax liabilities arise when income items are recognized in the financial statements before the tax returns or when
expenses are recognized in the tax return prior to the financial statements. Deferred tax assets and liabilities are measured using
enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be
recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the
period that includes the date when the change in the tax rate was enacted.
On December 22, 2017, the US Congress enacted the Tax Cuts and Jobs Act (Tax Reform Legislation), which made significant
changes to US federal income tax law affecting us. See Note 11. Income Taxes.
Treasury Stock We record treasury stock purchases at cost, which includes incremental direct transaction costs. Amounts are
recorded as reductions in shareholders’ equity in the consolidated balance sheets.
Revenue Recognition and Imbalances We record revenues from the sales of crude oil, natural gas and NGLs when the
product is delivered at a fixed or determinable price, title has transferred and collectibility is reasonably assured.
Basic and Diluted Earnings (Loss) Per Share Attributable to Noble Energy Basic earnings (loss) per share (EPS) of our
common stock is computed on the basis of the weighted average number of shares outstanding during each period. The diluted
EPS of our common stock includes the effect of outstanding common stock equivalents such as stock options, shares of
restricted stock, and/or shares of our stock held in a rabbi trust, except in periods in which there is a net loss.
Contingencies We are subject to legal proceedings, claims and liabilities that arise in the ordinary course of business. We
accrue for losses associated with legal claims when such losses are considered probable and the amounts can be reasonably
estimated. See Note 17. Commitments and Contingencies.
We self-insure the medical and dental coverage provided to certain employees, and the deductibles for workers’ compensation,
automobile liability and general liability coverage. Liabilities are accrued for self-insured claims, or when estimated losses
exceed coverage limits, and when sufficient information is available to reasonably estimate the amount of the loss.
Foreign Currency The US dollar is considered the functional currency for each of our international operations. Transactions
that are completed in foreign currencies are remeasured into US dollars and recorded in the financial statements at prevailing
foreign exchange rates. Transaction gains or losses are included in other non-operating (income) expense, net in the
consolidated statements of operations.
Segment Information Accounting policies for geographical segments are the same as those described above. Transfers
between segments are accounted for at market value. We do not consider interest income and expense or income tax benefit or
expense in our evaluation of the performance of geographical segments. See Note 14. Segment Information.
Revolving Credit Facilities In accordance with our accounting policy, we net intra-quarter revolving credit facility activity to
zero for purposes of consolidated statements of cash flows disclosure.
Recently Issued Accounting Standards
Revenue Recognition In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update
No. 2014-09 (ASU 2014-09), which creates Topic 606, Revenue from Contracts with Customers. In summary, revenue
recognition would occur upon 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. Additionally, ASU 2014-09
requires enhanced financial statement disclosures over revenue recognition.
We continue to evaluate the impact of ASU 2014-09 on our accounting policies, internal controls, and consolidated financial
statements and related disclosures. We are performing a review of contracts for each of our revenue streams and developing
accounting policies to address the provisions of ASU 2014-09. ASU 2014-09 also includes provisions regarding future revenues
and expenses under a gross-versus-net presentation. We are evaluating the impact, if any, on the presentation of future revenues
and expenses under this gross-versus-net presentation guidance. Based upon assessments performed to date, we do not expect
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ASU 2014-09 to have an effect on the timing of revenue recognition or our financial position. In addition, we expect the impact
regarding gross-versus-net presentation to involve certain presentation changes specifically related to domestic natural gas
processing revenues and expenses. The impact of such presentation changes will not impact our net income. The standard is
required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified
retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. We will adopt the new
standard on January 1, 2018, using the modified retrospective approach.
Compensation – Stock Compensation (Topic 718): Scope of Modification Accounting In May 2017, the FASB issued
Accounting Standards Update No. 2017-09 (ASU 2017-09) Compensation – Stock Compensation (Topic 718). The purpose of
this update is to provide clarity as to which modifications of awards require modification accounting under Topic 718, whereas
previously issued guidance frequently resulted in varying interpretations and a diversity of practice. An entity should employ
modification accounting unless the following are met: (1) the fair value of the award is the same immediately before and after
the award is modified; (2) the vesting conditions are the same under both the modified award and the original award; and (3)
the classification of the modified award is the same as the original award, either equity or liability. Regardless of whether
modification accounting is utilized, award disclosure requirements under Topic 718 remain unchanged. ASU 2017-09 will be
effective for annual or any interim periods beginning after December 15, 2017. We will adopt the new standard on the effective
date of January 1, 2018 and do not believe adoption will have a material impact on our financial statements.
Business Combinations – Clarifying the Definition of a Business In January 2017, the FASB issued Accounting Standards
Update No. 2017-01 (ASU 2017-01): Business Combinations – Clarifying the Definition of a Business, that assists in
determining whether certain transactions should be accounted for as acquisitions or dispositions of assets or businesses. The
amendment provides a screen to be applied to the fair value of an acquisition or disposal to evaluate whether the assets in
question are simply assets or if they are a business. If the screen is not met, no further evaluation is needed. If the screen is met,
certain steps are subsequently taken to make the determination. ASU 2017-01 is designed to reduce the number of transactions
accounted for as business transactions, which take more time and cost more to analyze than asset transactions. ASU 2017-01 is
effective for annual and interim periods beginning after December 15, 2017 and is required to be applied prospectively. Our
recent Clayton Williams Energy Acquisition was not impacted by this guidance, which we will apply to applicable and
qualifying transactions after adoption on January 1, 2018.
Statement of Cash Flows – Restricted Cash In November 2016, the FASB issued Accounting Standards Update No. 2016-18
(ASU 2016-18): Statement of Cash Flows – Restricted Cash, which requires amounts generally described as restricted cash and
restricted cash equivalents be included with cash and cash equivalents when reconciling the total beginning and ending amounts
for the periods shown on the statement of cash flows. ASU 2016-18 will be effective for annual and interim periods beginning
after December 15, 2017, with earlier application permitted. We will adopt the new standard on the effective date of January 1,
2018 and do not believe adoption will have a material impact on our consolidated statements of cash flows and related
disclosures.
Statement of Cash Flows – Classification of Certain Cash Receipts and Cash Payments In August 2016, the FASB issued
Accounting Standards Update No. 2016-15 (ASU 2016-15): Statement of Cash Flows – Classification of Certain Cash Receipts
and Cash Payments, to clarify how eight specific cash receipt and cash payment transactions should be presented in the
statement of cash flows. ASU 2016-15 will be effective for annual and interim periods beginning after December 15, 2017, with
earlier application permitted. We will adopt the new standard on the effective date of January 1, 2018 and do not believe
adoption will have a material impact on our consolidated statements of cash flows and related disclosures as this update pertains
to classification of items and is not a change in accounting principle.
Leases In February 2016, the FASB issued Accounting Standards Update No. 2016-02 (ASU 2016-02): Leases. The guidance
requires lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by leases with
terms of more than 12 months. ASU 2016-02 also requires disclosures designed to give financial statement users information on
the amount, timing, and uncertainty of cash flows arising from leases. The standard will be effective for annual and interim
periods beginning after December 15, 2018, with earlier application permitted.
In the normal course of business, we enter into capital and operating lease agreements to support our exploration and
development operations and lease assets such as drilling rigs, platforms, storage facilities, field services and well equipment,
pipeline capacity, office space and other assets.
We will adopt the new standard on the effective date of January 1, 2019. At this time, we cannot reasonably estimate the impact
ASU 2016-02 will have on our consolidated financial statements; however, we believe adoption and implementation of ASU
2016-02 will have a material impact on our consolidated balance sheet resulting from an increase in both assets and liabilities
relating to leasing activities. As part of our assessment to date, we have formed an implementation work team, prepared
educational and training materials pertinent to ASU 2016-02 and have begun contract review and documentation.
103
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Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Intangibles – Goodwill and Other – Simplifying the Test for Goodwill Impairment In January 2017, the FASB issued
Accounting Standards Update No. 2017-04 (ASU 2017-04): Intangibles – Goodwill and Other – Simplifying the Test for
Goodwill Impairment, to simplify how an entity is required to test goodwill for impairment by eliminating Step 2 from the
goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s
goodwill with the carrying amount of that goodwill. Under the new guidance, an entity will perform its annual, or interim,
goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount, with an impairment charge
being recognized for the amount by which the carrying amount exceeds the reporting unit’s fair value. ASU 2017-04 will be
effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019, with early
adoption permitted. We are currently evaluating the provisions of ASU 2017-04 and have not yet determined if we will early
adopt.
Financial Instruments – Credit Losses In June 2016, the FASB issued Accounting Standards Update No. 2016-13 (ASU
2016-13): Financial Instruments – Credit Losses, which replaces the incurred loss impairment methodology in current US
GAAP with a methodology that reflects expected credit losses. The update is intended to provide financial statement users with
more useful information about expected credit losses. The amended guidance is effective for fiscal years beginning after
December 15, 2019, with early adoption permitted. We will adopt the new standard on the effective date of January 1, 2020 and
are currently evaluating the effect, if any, that the guidance will have on our consolidated financial statements and related
disclosures.
SAB 118 On December 22, 2017, the SEC staff issued Staff Accounting Bulletin No. 118 (SAB 118) to address the application
of US GAAP in situations when a registrant does not have the necessary information available, prepared, or analyzed (including
computations) in reasonable detail to complete the accounting for certain income tax effects relating to the Tax Reform
Legislation. SAB 118 provides guidance for registrants under three scenarios:
1) if measurement of certain income tax effects is complete, registrants must reflect the tax effects of the Tax Reform
Legislation for which the accounting is complete;
2) if measurement of certain income tax effects can be reasonably estimated, registrants must report provisional amounts for
those specific income tax effects of the Tax Reform Legislation for which the accounting is incomplete but a reasonable
estimate can be determined. Provisional amounts or adjustments to provisional amounts identified in the measurement
period, as defined, should be included as an adjustment to tax expense or benefit from continuing operations in the period
the amounts are determined; and
3) if measurement of certain income tax effects cannot be reasonably estimated, registrants are not required to report
provisional amounts for any specific income tax effects of the Tax Reform Legislation for which a reasonable estimate
cannot be determined, and would continue to apply ASC 740 – Income Taxes based on the provisions of the tax laws that
were in effect immediately prior to the enactment of the Tax Reform Legislation. Registrants would report the provisional
amounts of the tax effects of the Tax Reform Legislation in the first reporting period in which a reasonable estimate can be
determined.
The SEC staff believes that in no circumstances should the measurement period extend beyond December 22, 2018, one year
from the enactment of the Tax Reform Legislation. See Note 11. Income Taxes.
104
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Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 2. Additional Financial Statement Information
Additional statements of operations information is as follows:
Year Ended December 31,
2016
$
$
$
$
$
$
$
$
$
$
2015
2017
563
127
306
996
571
138
432
1,141
542
78
480
1,100
113
266
34
43
32
488
148
579
76
77
45
925
62
9
27
55
35
188
(millions)
Production Expense
Lease Operating Expense
Production and Ad Valorem Taxes
Gathering, Transportation and Processing Expense (1)
Total
Exploration Expense
Leasehold Impairment and Amortization (2)
Dry Hole Cost
Seismic, Geological and Geophysical
Staff Expense
Other
Total
Loss on Marcellus Shale Upstream Divestiture
Loss on Sale
Firm Transportation Commitment (2)
Other(3)
Total
Other Operating (Income) Expense, Net
Marketing Expense (4)
Clayton Williams Acquisition Expenses (5)
Corporate Restructuring Expense (6)
Pension Plan Expense (7)
Impact of Rosetta Merger (8)
North Sea Remediation Project Revision (9)
Loss on Asset Due to Terminated Contract (10)
Gain on Divestitures, Net (11)
Other, Net
Total
(1) Certain of our gathering and processing expenses were historically presented as components of other operating expense, net, in our
consolidated statement of operations. Beginning in 2017, we changed our presentation to reflect these as components of production
expense. These costs are now included within gathering, transportation and processing expense. For the years ended December 31, 2016
and 2015, these costs totaled $17 million and $17 million, respectively, and have been reclassified from other operating expense, net to
conform to current presentation.
58
—
8
—
(25)
—
41
(238)
53
(103) $
47
100
—
—
—
(42)
—
(326)
33
(188) $
— $
—
—
— $
2,270
93
16
2,379
33
—
51
88
81
—
—
—
79
332
—
—
—
—
$
$
$
$
$
$
$
$
$
$
(2) See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
(3) Expense relates to unutilized commitments associated with Marcellus Shale firm transportation contracts. See Note 17. Commitments
and Contingencies.
(4) Amount includes costs for legal and advisory services and employee severance charges.
(5) Expense relates to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain
commitments.
(6) See Note 3. Clayton Williams Energy Acquisition.
(7) Expenses are associated with corporate organizational activities.
(8) Amount includes reclassification of the actuarial loss from AOCL related to the re-measurement and termination of our defined benefit
pension plan to net income (loss).
(9) Amounts represent a purchase price allocation adjustment in 2016 and merger expenses in 2015. See Note 4. Acquisitions, Divestitures
and Merger.
(10) See Note 9. Asset Retirement Obligations.
(11) Amount relates to the termination of a rig contract offshore Falkland Islands as a result of a supplier's non-performance.
(12) See Note 4. Acquisitions, Divestitures and Merger.
105
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Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Additional balance sheet information is as follows:
(millions)
Accounts Receivable, Net
Commodity Sales
Joint Interest Billings
Proceeds Receivable (1)
Other
Allowance for Doubtful Accounts
Total
Other Current Assets
Inventories, Materials and Supplies
Inventories, Crude Oil
Assets Held for Sale(2)
Restricted Cash (3)
Prepaid Expenses and Other Assets, Current
Total
Other Noncurrent Assets
Equity Method Investments
Mutual Fund Investments
Net Deferred Income Tax Asset
Other Assets, Noncurrent
Total
Other Current Liabilities
Production and Ad Valorem Taxes
Commodity Derivative Liabilities, Current
Income Taxes Payable
Asset Retirement Obligations, Current
Interest Payable
Compensation and Benefits Payable
Current Portion of Capital Lease and Other Obligations
Other Liabilities, Current
Total
Other Noncurrent Liabilities
Deferred Compensation Liabilities, Noncurrent
Asset Retirement Obligations, Noncurrent
Production and Ad Valorem Taxes
Marcellus Firm Transportation Commitment, Noncurrent (4)
Other Liabilities, Noncurrent
Total
December 31,
2017
2016
$
$
$
$
$
$
$
$
$
$
455
207
—
103
(17)
748
66
16
629
38
31
780
305
57
25
74
461
84
58
18
51
67
98
61
141
578
197
824
69
76
79
1,245
$
$
$
$
$
$
$
$
$
$
403
106
40
86
(20)
615
71
18
18
30
23
160
400
71
—
37
508
115
102
53
160
76
110
63
63
742
218
775
47
—
63
1,103
(1) Proceeds relate to the farm-out of a 35% interest in Block 12 offshore Cyprus and were received in January 2017. See Note 4.
Acquisitions, Divestitures and Merger.
(2) Assets held for sale at December 31, 2017 include assets in the Greeley Crescent area of the DJ Basin, a 7.5% interest in the Tamar and
Dalit fields, offshore Israel, certain non-strategic assets acquired in the Clayton Williams Energy Acquisition and the CONE investments.
Assets held for sale at December 31, 2016 include assets in the Greeley Crescent area of the DJ Basin. See Note 4. Acquisitions,
Divestitures and Merger.
(3) Balance at December 31, 2017 represents amount held in escrow for the purchase of a midstream entity. Balance at December 31, 2016
represents amount held in escrow for the purchase of certain Delaware Basin properties. See Note 4. Acquisitions, Divestitures and
Merger.
(4) Relates to unutilized commitments associated with Marcellus Shale firm transportation contracts. See Note 4. Acquisitions, Divestitures
106
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Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
and Merger.
Supplemental statements of cash flow information is as follows:
(millions)
Cash Paid During the Year For
Interest, Net of Amount Capitalized
Income Taxes Paid, Net
Non-Cash Financing and Investing Activities
Increase in Capital Lease and Other Obligations
Note 3. Clayton Williams Energy Acquisition
Year Ended December 31,
2016
2017
2015
$
$
346
121
$
327
236
—
5
260
202
55
In January 2017, we announced the Clayton Williams Energy Acquisition, which was approved by Clayton Williams Energy
stockholders and closed on April 24, 2017. Acquired assets include 71,000 highly contiguous net acres in the core of the
Delaware Basin adjacent to our Reeves County holdings in Texas, and an additional 100,000 net acres in other areas of
the United States. In total, the acquisition increased our Delaware Basin position to approximately 117,000 net acres.
See Supplemental Oil and Gas Information (Unaudited), below for discussion of proved reserves acquired. In addition, upon
closing of the acquisition, approximately 64,000 net acres in Reeves County, Texas were dedicated to Noble Midstream
Partners for infield crude oil, natural gas and produced water gathering.
The acquisition was effected through the issuance of approximately 56 million shares of Noble Energy common stock with a
fair value of approximately $1.9 billion and cash consideration of $637 million, for total consideration of approximately $2.5
billion, in exchange for all outstanding Clayton Williams Energy shares, including stock options, restricted stock awards and
warrants. The closing price of our stock on the New York Stock Exchange (NYSE) was $34.17 on April 24, 2017. In connection
with the transaction, we borrowed $1.3 billion under our Revolving Credit Facility (defined below) to fund the cash portion of
the acquisition consideration, redeem outstanding Clayton Williams Energy debt, pay associated make-whole premiums and
pay related fees and expenses. See Note 10. Long-Term Debt.
In connection with the Clayton Williams Energy Acquisition, we have incurred acquisition-related costs of $100 million to date,
including $64 million of severance, consulting, investment, advisory, legal and other merger-related fees and $36 million of
noncash share-based compensation expense, all of which were expensed and are included in other operating expense, net in our
consolidated statements of operations. In addition, we received approximately 720,000 shares of common stock from Clayton
Williams Energy shareholders for the payment of withholding taxes due on the vesting of their restricted stock and options
pursuant to the purchase and sale agreement, resulting in a $25 million increase in our treasury stock balance.
Purchase Price Allocation The transaction has been accounted for as a business combination, using the acquisition method.
The following table represents the preliminary allocation of the total purchase price of Clayton Williams Energy to the assets
acquired and the liabilities assumed based on the fair value at the acquisition date, with any excess of the purchase price over
the estimated fair value of the identifiable net assets acquired recorded as goodwill.
Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, analysis
of the underlying tax basis of Clayton Williams Energy's assets and liabilities, and final appraisals of assets acquired and
liabilities assumed. We expect to complete the purchase price allocation during the 12-month period following the acquisition
date, during which time the value of the assets and liabilities, including any goodwill, may be revised as appropriate.
107
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Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
The following table sets forth our preliminary purchase price allocation:
(millions, except per share amounts)
Fair Value of Common Stock Issued
Plus: Cash Consideration Paid to Clayton Williams Energy Stockholders
Total Purchase Price
Plus Liabilities Assumed by Noble Energy:
Accounts Payable
Other Current Liabilities
Long-Term Deferred Tax Liability
Long-Term Debt
Asset Retirement Obligations
Total Purchase Price Plus Liabilities Assumed
The fair values of Clayton Williams Energy's identifiable assets are as follows:
(millions)
Cash and Cash Equivalents
Other Current Assets
Oil and Gas Properties:
Proved Reserves
Undeveloped Leasehold Cost
Gathering and Processing Assets
Asset Retirement Costs
Other Property Plant and Equipment
Implied Goodwill
Total Asset Value
$
$
$
$
$
1,876
637
2,513
99
38
509
595
63
3,817
21
70
722
1,571
48
63
12
1,310
3,817
In connection with the acquisition, we assumed, and then subsequently retired, all of Clayton Williams Energy's long-term debt
at a cost to us of $595 million. The fair value measurements of long-term debt were estimated based on the early redemption
prices and represent Level 1 inputs.
The fair value measurements of crude oil and natural gas properties and asset retirement obligations are based on inputs that are
not observable in the market and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and
asset retirement obligations were measured using valuation techniques that convert expected future cash flows to a single
discounted amount. Significant inputs to the valuation of crude oil and natural gas properties included estimates of: (i) proved,
possible and probable reserves; (ii) production rates and related development timing; (iii) future operating and development
costs; (iv) future commodity prices; and (v) a market-based weighted average cost of capital rate. These inputs required
significant judgments and estimates by management at the time of the valuation and are the most sensitive and may be subject
to change.
Based upon the preliminary purchase price allocation, we have recognized $1.3 billion of goodwill, all of which is assigned to
the Texas reporting unit. As a result of the acquisition, we expect to realize certain synergies which may result from our control
of the combined assets as well as future midstream opportunities. The oil-rich geology of these assets, coupled with our
unconventional expertise and position in the adjacent properties, significantly enhances our crude oil focus and growth outlook.
The acquisition provides for synergies related to administrative and capital efficiencies, and increased opportunities to drill
longer lateral wells on our combined acreage positions, enhances our crude oil production base and future crude oil growth
potential. It also adds to our midstream assets and provides future midstream build-out opportunities for the gathering,
processing and servicing of future production in the basin.
Results of Operations The results of operations attributable to Clayton Williams Energy are included in our consolidated
statements of operations beginning on April 24, 2017. We generated revenues of $99 million and a pre-tax loss of $19 million
from the Clayton Williams Energy assets during the period April 24, 2017 to December 31, 2017.
Pro Forma Financial Information The following pro forma condensed combined financial information was derived from the
historical financial statements of Noble Energy and Clayton Williams Energy and gives effect to the acquisition as if it had
occurred on January 1, 2016. The information below reflects pro forma adjustments based on available information and certain
assumptions that we believe are reasonable, including (i) Noble Energy's common stock and equity awards issued to convert
Clayton Williams Energy's outstanding shares of common stock and equity awards and conversion of warrants as of the closing
108
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Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
date of the acquisition, (ii) depletion of Clayton Williams Energy's fair-valued proved crude oil and natural gas properties, and
(iii) the estimated tax impacts of the pro forma adjustments.
Additionally, pro forma earnings for the year ended December 31, 2017 were adjusted to exclude acquisition-related costs
of $100 million incurred by Noble Energy and $23 million incurred by Clayton Williams Energy. The pro forma results of
operations do not include any cost savings or other synergies that we expect to realize from the Clayton Williams Energy
Acquisition or any estimated costs that have been or will be incurred by us to integrate the Clayton Williams Energy assets. The
pro forma condensed combined financial information has been included for comparative purposes and is not necessarily
indicative of the results that might have actually occurred had the Clayton Williams Energy Acquisition taken place on January
1, 2016; furthermore, the financial information is not intended to be a projection of future results.
(millions, except per share amounts)
Revenues
Net Loss and Comprehensive Loss Attributable to Noble Energy
Net Loss Attributable to Noble Energy per Common Share
Basic and Diluted
Note 4. Acquisitions, Divestitures and Merger
Year Ended December 31,
2017
2016
$
$
$
4,304
(678)
3,651
(1,082)
(1.39) $
(2.23)
We maintain an ongoing portfolio management program and have engaged in various transactions over recent years.
Year Ended December 31, 2017
Marcellus Shale Upstream Divestiture On June 28, 2017, we closed the sale of all of our Marcellus Shale upstream assets,
which were primarily natural gas properties. The sales price totaled $1.2 billion, and we received $1.0 billion of net cash
proceeds, after consideration of customary adjustments, at closing. The sales price includes additional contingent consideration
of up to $100 million structured as three separate payments of $33.3 million each. The contingent payments are in effect should
the average annual price of the Appalachia Dominion, South Point index exceed $3.30 per MMBtu in the individual annual
periods from 2018 through 2020. To date, conditions for the recognition of the contingent consideration are not probable and,
therefore, no amounts have been accrued related to the contingent consideration. Proceeds from the transaction were used to
repay borrowings resulting from the Clayton Williams Energy Acquisition. See Note 10. Long-Term Debt.
For the year ended December 31, 2017, we recognized a total loss of $2.4 billion, or $1.5 billion after-tax, on this divestiture.
The aggregate net book value of the properties sold was approximately $3.4 billion, which included approximately $883 million
of undeveloped leasehold cost.
As part of the loss, we accrued non-cash exit costs of $41 million, discounted, relating to a retained transportation contract that
is currently in service; however, we no longer have production to satisfy this commitment and do not plan to utilize this
capacity in the future. In addition, we recorded a $52 million accrual, discounted, relating to future commitments to a third
party who assumed a portion of our retained capacity relating to other pipeline projects. Both charges are included in loss on
Marcellus Shale upstream divestiture in our consolidated statements of operations in accordance with accounting for exit or
disposal activities under ASC 420 – Exit or Disposal Cost Obligations.
Other retained Marcellus Shale firm transportation contracts relate to pipeline projects that are not yet commercially available
to us. These projects that are not yet available will undergo construction and, as these projects become commercially available
to us, we will assess, based upon the facts and circumstances, the recognition of any potential exit cost liabilities. It is likely we
will incur additional firm transportation costs associated with this exit activity in the future. See Note 2. Additional Financial
Statement Information and Note 17. Commitments and Contingencies.
Production from the Marcellus Shale upstream assets represented 204 MMcfe/d of total consolidated sales volumes for the year
ended December 31, 2017. See Supplemental Oil and Gas Information (Unaudited), below for discussion of reserves divested.
109
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Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Divestiture of 7.5% Interest in Tamar and Dalit Fields The terms of the Israel Natural Gas Framework (Framework) require
us to reduce our current ownership interest in the Tamar and Dalit fields from 32.5% to 25% by year-end 2021. On January 29,
2018, we signed a definitive agreement to divest a 7.5% working interest in each of the fields to Tamar Petroleum Ltd. (TASE:
TMRP) (Tamar Petroleum) for cash proceeds of approximately $560 million and 38.5 million shares of Tamar Petroleum.
Closing of the transaction is expected by the end of first quarter 2018, subject to satisfactory conclusion of Tamar Petroleum's
debt financing and customary approvals, terms and conditions. As of December 31, 2017, the net book value of the 7.5%
interest, $293 million, was included in assets held for sale.
Divestiture of Southwest Royalties In January 2018, we signed an agreement to sell our interest in Southwest Royalties, Inc.
(Southwest Royalties), a subsidiary of Clayton Williams Energy, and acquired as part of Clayton Williams Energy Acquisition.
We received proceeds of $60 million on sale of these assets. As of December 31, 2017, the asset value of these properties of
$102 million and associated asset retirement obligation of $42 million were included in assets and liabilities held for sale.
Other US Onshore Transactions We conducted the following additional transactions in 2017:
• US Onshore Divestitures During 2017, we received total proceeds of $671 million resulting from the sale of certain
US onshore properties, including $568 million related to divestment of non-core acreage in the DJ Basin. Proceeds
were applied to reduce field basis with no recognition of gain or loss. A subsequent closing for certain non-core DJ
Basin operated properties, in the amount of approximately $40 million, is expected to occur in mid-2018.
•
Sale of Mineral and Royalty Assets We received $335 million and recognized a gain of $334 million on the sale of
mineral and royalty assets covering approximately 140,000 net mineral acres concentrated primarily in Texas,
Oklahoma and North Dakota.
• Delaware Basin Acquisition In January 2017, we completed the acquisition of Delaware Basin properties, including
seven producing wells, thus increasing our contiguous acreage position in the Reeves County area. Consideration
totaled $301 million, approximately $246 million of which was allocated to undeveloped leasehold cost. Initial
consideration of $30 million was paid into an escrow account in fourth quarter 2016 and reflected as a restricted asset
in our consolidated balance sheet as of December 31, 2016.
Marcellus Shale CONE Gathering Divestiture In December 2017, we signed an agreement to sell our 50% interest in CONE
Gathering LLC (CONE Gathering) to CNX Resources Corporation. CONE Gathering owns the general partner of CONE
Midstream Partners LP (CONE Midstream), which constructs, owns and operates natural gas gathering and other midstream
energy assets in the Marcellus Shale. At December 31, 2017, our total investment of $181 million in the CONE entities was
included in assets held for sale. We closed the sale in January 2018, receiving proceeds of $308 million in cash and utilized
proceeds to pay down borrowings under the Revolving Credit Facility. We now hold 21.7 million common units representing a
33.5% limited partner interests in CNX Midstream Partners LP (NYSE: CNXM). As of December 31, 2017, the net book value
of the limited partner interests was approximately $70 million.
Noble Midstream Partners Asset Contribution On June 26, 2017, Noble Midstream Partners acquired an additional 15%
limited partner interest in Blanco River DevCo LP (Blanco River DevCo), increasing its ownership to 40% of the Blanco River
DevCo LP, and acquired the remaining 20% limited partner interest in Colorado River DevCo LP (Colorado River DevCo)
from us for $270 million.
Blanco River DevCo holds Noble Midstream Partners’ Delaware Basin in-field gathering dedications for crude oil and
produced water gathering services on approximately 111,000 net acres, with substantially all of the acreage also dedicated for
natural gas gathering. Colorado River DevCo provides services across our development areas in the DJ Basin, including crude
oil and natural gas gathering and water services in the Wells Ranch area and crude oil gathering in the East Pony area.
The $270 million consideration consisted of $245 million in cash and 562,430 common units representing limited partner
interests in Noble Midstream Partners. Noble Midstream Partners funded the cash consideration with approximately $138
million of net proceeds from a concurrent private placement of common units and $90 million of borrowings under the Noble
Midstream Services Revolving Credit Facility (defined below) and the remainder from cash on hand.
Noble Midstream Partners Advantage Joint Venture On April 3, 2017, Noble Midstream Partners and Plains Pipeline, L.P., a
wholly owned subsidiary of Plains All American Pipeline, L.P., acquired Advantage Pipeline, L.L.C. (Advantage Pipeline)
for $133 million through a newly formed 50/50 joint venture (Advantage Joint Venture). Noble Midstream Partners contributed
approximately $67 million of cash to the Advantage Joint Venture, funded by available cash on hand and the Noble Midstream
Services Revolving Credit Facility. The Advantage Joint Venture is accounted for under the equity method and is included
within our Midstream segment. See Note 7. Equity Method Investments.
110
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Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Noble Midstream Partners serves as operator of the Advantage Pipeline System, which includes a 70-mile crude oil pipeline in
the Delaware Basin from Reeves County, Texas to Crane County, Texas with 150 MBbls per day of shipping capacity and 490
MBbls of storage capacity.
Noble Midstream Partners Black Diamond Gathering In December 2017, Noble Midstream Partners and Greenfield
Midstream, LLC, a portfolio company of EnCap Flatrock Midstream Gathering, formed an entity, Black Diamond Gathering,
LLC (Black Diamond Gathering). Black Diamond Gathering subsequently entered into definitive agreements to acquire Saddle
Butte Rockies Midstream, LLC and affiliates (collectively, Saddle Butte). The Saddle Butte purchase closed on January 31,
2018, for total cash consideration of approximately $638.5 million. Noble Midstream Partners funded its share of the purchase
price with proceeds from its December 2017 common unit offering, cash on hand and borrowings under its unsecured revolving
credit facility. See Note 10. Long-Term Debt.
Noble Midstream partners received a 54.4% ownership interest in Black Diamond. Noble Midstream Partners fully consolidates
the assets and liabilities of Black Diamond Gathering.
Noble Midstream Partners will serve as operator of Saddle Butte assets which include a large-scale integrated crude oil
gathering system in the DJ Basin, consisting of approximately 160 miles of pipeline in operation, 300 MBbls per day of
delivery capacity and approximately 210 MBbls of crude oil storage capacity. Saddle Butte has approximately 141,000
dedicated acres from six customers under fixed fee arrangements.
Subsequent Event - Gulf of Mexico Divestiture On February 15, 2018, we announced the Company signed a definitive
agreement to sell its assets in the Gulf of Mexico for cash consideration of $480 million. As part of the transaction, the buyer
will assume all abandonment obligations associated with the properties which we estimate to approximate $230 million as of
December 31, 2017. The net book value of the Gulf of Mexico assets as of December 31, 2017 was approximately $750
million. We expect to incur a charge in early 2018, subject to customary closing adjustments. The transaction is expected to
close during second quarter 2018, contingent upon the buyer’s successful implementation of its contemplated restructuring, and
will be effective as of January 1, 2018.
Year Ended December 31, 2016
Termination of Marcellus Shale JDA In fourth quarter 2016, we and CONSOL Energy Inc. (CONSOL) agreed to terminate our
50-50 Joint Development Agreement (JDA) in the Marcellus Shale. In connection with the terminated JDA, we executed and
closed an exchange agreement whereby we and CONSOL each transferred all of our interest in a portion of co-owned
properties to one another. In addition to the acreage and production realignment between the two companies, we remitted a cash
payment of approximately $213 million to CONSOL at closing. Terminating the JDA resulted in the elimination of the
remaining outstanding carried cost obligation due from us. No gain or loss was recognized on the exchange.
DJ Basin Acreage Exchange We closed a cashless acreage exchange in the DJ Basin receiving approximately 11,700 net acres
within our Wells Ranch development area in exchange for approximately 13,500 net acres primarily from our Bronco area. No
gain or loss was recognized.
2016 Divestitures During 2016, we engaged in the following sales transactions:
•
•
•
•
entered an agreement to divest certain producing and non-producing properties covering approximately 33,100 net
acres in the DJ Basin for proceeds of $505 million. We closed the sale on a portion of the properties in 2016, receiving
proceeds of $486 million, with the remainder of the sale closing in 2017. Proceeds were applied to reduce field basis
with no recognition of gain or loss;
sold additional DJ Basin non-producing properties, certain Eagle Ford properties, our Bowdoin property in northern
Montana, and certain other smaller US onshore properties, generating total net proceeds of $152 million, a net loss of
$23 million on the Bowdoin sale, and no further gain or loss recognized on the remaining transactions;
sold our 47% interest in the Alon A and Alon C licenses, which included the Karish and Tanin fields, offshore Israel,
for a total sales price of $73 million ($67 million for asset consideration and $6 million from cost adjustments).
Proceeds were applied to reduce field basis with no recognition of gain or loss;
sold a 3.5% working interest in the Tamar and Dalit fields, offshore Israel, in compliance with the terms of the
Framework, which requires us to reduce our ownership interest in the fields to 25% by year-end 2021. The sales price
totaled $431 million, and we received net cash proceeds of $316 million, after consideration of timing and tax
adjustments, at closing. Proceeds were ratably applied to the fields basis and resulted in the recognition of a $261
million gain; and
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Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
•
received proceeds of $131 million related to the farm-out of a 35% interest in Block 12, which includes the Aphrodite
natural gas discovery, offshore Cyprus. We received the remaining proceeds of $40 million in January 2017. Proceeds
were applied to reduce field basis with no recognition of gain or loss.
Year Ended December 31, 2015
2015 Divestitures In 2015, we sold certain non-strategic US onshore properties, receiving proceeds of $151 million, with no
gain or loss recorded.
Rosetta Merger On July 20, 2015, Noble Energy completed the Rosetta Merger. The merger was effected through the issuance
of approximately 41 million shares of Noble Energy common stock in exchange for all outstanding shares of Rosetta using a
ratio of 0.542 of a share of Noble Energy common stock for each share of Rosetta common stock and the assumption of
Rosetta's liabilities, including approximately $2 billion fair value of outstanding debt.
The merger added two new US onshore shale positions to our portfolio including approximately 50,000 net acres in the Eagle
Ford Shale and 54,000 net acres in the Delaware Basin (45,000 acres in the Delaware Basin and 9,000 acres in the Midland
Basin). In connection with the Rosetta Merger, we incurred merger-related costs of approximately $81 million, including (i)
$66 million of severance, consulting, investment, advisory, legal and other merger-related fees, and (ii) $15 million of noncash
share-based compensation expense, all of which were expensed and are included in other operating (income) expense, net.
Purchase Price Allocation The merger was accounted for as a business combination, using the acquisition method. The
allocation of the total purchase price of Rosetta to the assets acquired and the liabilities assumed was based on the fair values at
the merger date, with the excess of the purchase price over the fair values of the identifiable net assets acquired recorded as
goodwill.
Results of Operations The results of operations attributable to Rosetta are included in our consolidated statements of
operations beginning on July 21, 2015. Revenues of $457 million and pre-tax net loss of $20 million, exclusive of a $25 million
purchase price allocation adjustment, from Rosetta were generated for the year ended December 31, 2016. Revenues of $181
million and pre-tax net loss of $120 million, inclusive of a $163 million goodwill impairment, from Rosetta were generated
from July 21, 2015 to December 31, 2015.
See Supplemental Oil and Gas Information (Unaudited), below, for discussion of proved reserves added or divested in
connection with the above transactions.
Note 5. Asset Impairments
Pre-tax (non-cash) asset impairment charges were as follows:
(millions)
Gulf of Mexico
Israel
Equatorial Guinea
Other International
Total
Year Ended December 31,
2016
2015
2017
$
$
63
—
—
7
70
$
$
— $
88
—
4
92
$
158
36
339
—
533
2017 Asset Impairments During 2017, we recorded a non-cash property impairment charge related to our decision not to
pursue development of the Troubadour natural gas discovery in the Gulf of Mexico.
2016 Asset Impairments While the Leviathan natural gas development project, offshore Israel, was not formally sanctioned at
December 31, 2016, in fourth quarter 2016, we selected the initial development concept for the first phase of development and
wrote off $88 million associated with certain development concepts that were not selected.
2015 Asset Impairments During 2015, certain properties were written down to their estimated fair values using a discounted
cash flow model. The cash flow model included management’s estimates of future crude oil and natural gas production,
commodity prices based on forward commodity price curves or contract prices as of the date of the estimate, operating and
development costs, and discount rates. Impairment charges of $481 million resulted from reductions in the forward crude oil
prices as of December 31, 2015.
We also recorded impairment charges of approximately $47 million primarily related to revisions in expected field
abandonment and other costs for properties in the Gulf of Mexico and offshore Israel and $5 million related to the pending sale
of our interest in the Alon A and Alon C licenses, offshore Israel, which included the Karish and Tanin fields.
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Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs
Capitalized Exploratory Well Costs We capitalize exploratory well costs until a determination is made that the well has found
proved reserves or is deemed noncommercial. If a well is deemed to be noncommercial, the well costs are immediately charged
to exploration expense as dry hole cost. In addition, wells costs associated with a discovery may be charged to impairment
expense if we choose not to pursue development activities.
Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently
expensed in the same period:
(millions)
Capitalized Exploratory Well Costs, Beginning of Period
Year Ended December 31,
2016
2015
2017
$
768
$
1,353
$
1,337
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved
Reserves
Divestitures and Other (1)
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved
Reserves or to Assets Held for Sale (2)
Capitalized Exploratory Well Costs Charged to Expense (3)
Capitalized Exploratory Well Costs, End of Period
$
20
—
(203)
(65)
520
$
84
(143)
(1)
(525)
768
$
123
—
(19)
(88)
1,353
(1) The 2016 amount relates to the farm-down of a 35% interest in Block 12 offshore Cyprus to a new partner.
(2) The 2017 amount relates to the approval and sanction of the first phase of development of the Leviathan field, offshore Israel.
The 2015 amount relates primarily to US onshore exploration activity.
(3) Capitalized exploratory well costs charged to expense are included within exploration or impairment expense in our consolidated
statements of operations.
The 2017 amount relates primarily to the write-off of costs associated with the Troubadour natural gas discovery, Gulf of Mexico, for
which we chose not to pursue development activities. See Note 5. Asset Impairments.
The 2016 amount relates primarily to discoveries offshore West Africa. Following review of additional 3D seismic data, we determined
these discoveries were impaired in the current forward outlook for crude oil prices. We also incurred expenses associated with the
Silvergate exploratory well in the Gulf of Mexico. The well did not encounter commercial hydrocarbons and was plugged and abandoned.
The 2015 amount relates primarily to a property in northeast Nevada. After assessing its commercial viability in the current commodity
price environment, we elected to discontinue exploration efforts.
The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced, and the
number of projects that have been capitalized for a period greater than one year:
(millions)
Exploratory Well Costs Capitalized for a Period of One Year or Less
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since
Commencement of Drilling
Balance at End of Period
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a
Period Greater Than One Year Since Commencement of Drilling
$
$
December 31,
2016
2017
2015
10
$
69
$
95
510
520
8
$
699
768
10
$
1,258
1,353
14
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Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
The following table provides a further aging of those exploratory well costs that have been capitalized for a period greater than
one year since the commencement of drilling as of December 31, 2017:
Country/Project
(millions)
Gulf of Mexico
Total
Suspended Since
2013 -
2014
2012 &
Prior
2015 -
2016
Katmai
$
147
$
56
$
91
$ —
Offshore Equatorial Guinea
Felicita (Block O)
Yolanda (Block I)
Offshore Cameroon
47
23
3
1
12
32
6
16
YoYo (YoYo Block)
Offshore Israel
55
4
6
45
Leviathan-1 Deep
Dalit
Offshore Cyprus
91
32
8
3
10
73
5
24
Progress
Progressing a development scenario for this 2014 crude
oil discovery. We are currently conducting feasibility
and front-end engineering and design studies on host
platform options.
Evaluating regional development scenarios for this 2008
gas discovery. During 2014, we conducted additional
seismic activity over Blocks I and O and in early 2016,
we began analyzing, interpreting and evaluating the
acquired seismic data.
A data exchange agreement for the 2007 Yolanda
condensate and natural gas discovery has been executed
between the governments of Equatorial Guinea and
Cameroon. Our natural gas development team is
working with the governments of Equatorial Guinea and
Cameroon to evaluate natural gas monetization options
for both Yolanda and YoYo (Cameroon) discoveries.
A data exchange agreement for the 2007 YoYo
condensate and natural gas discovery has been executed
between the governments of Equatorial Guinea and
Cameroon. Our natural gas development team is
working with both governments to evaluate natural gas
monetization options for both Yolanda (Equatorial
Guinea) and YoYo discoveries. In June 2017, we
converted our mining concession license for the YoYo
block into a PSC.
The well did not reach the target interval in 2012. We
continue to reprocess and review seismic information
for this discovery, based on information obtained from
other recent discoveries in the region, and develop
future drilling plans to test this deep oil concept, which
is held by the Leviathan Development and Production
Leases.
Our future development plan was approved by the
Government of Israel to develop this 2009 natural gas
discovery with a tie-in to existing infrastructure at
Tamar. See also Note 4. Acquisitions, Divestitures and
Merger.
In 2016, we farmed-down a 35% interest in Block 12
and submitted an updated development plan. We
continue to work with the Government of Cyprus to
obtain approval of the development plan and the
subsequent issuance of an Exploitation License.
Receiving an Exploitation License will allow us and our
partners to perform the necessary engineering and
design studies and progress the project to final
investment decision. During 2017, we submitted an
updated development plan, progressed capital project
cost improvement and continued regional natural gas
marketing efforts.
Cyprus
Other
Projects less than $20 million
Total
97
18
510
$
15
52
30
(9)
81
$
21
203
$
6 Continuing to assess and evaluate wells.
$
226
Undeveloped Leasehold Costs We reclassify undeveloped leasehold costs to proved property costs when proved reserves,
including PUDs, become attributable to the property as a result of our exploration and development activities. On the other
114
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Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
hand, if, based upon a change in exploration plans, timing and extent of development activities, availability of capital and
suitable rig and drilling equipment, resource potential, comparative economics, changing regulations and/or other factors, an
impairment is indicated, we record impairment expense related to the respective leases or licenses.
As of December 31, 2017, we had remaining undeveloped leasehold costs, to which proved reserves had not been attributed, of
$2.8 billion, including $1.6 billion related to Delaware Basin assets acquired in the Clayton Williams Energy Acquisition in
2017, and $1.1 billion and $149 million attributable to Delaware Basin and Eagle Ford Shale assets, respectively, acquired in
the Rosetta Merger in 2015. Undeveloped leasehold costs were derived from allocated fair values as a result of business
combinations or other purchases of unproved properties and are subject to impairment testing.
The remaining balance of undeveloped leasehold costs as of December 31, 2017 included $44 million related to Gulf of Mexico
unproved properties and $53 million related to international unproved properties. These costs pertain to acquired leases or
licenses that are subject to expiration over the next several years unless production is established on units containing the
acreage. These costs are evaluated as part of our periodic impairment review.
During 2017, we completed geological evaluations of certain Gulf of Mexico leases and licenses and leases and licenses
associated with other international unproved properties. We determined that several leases and licenses should be relinquished
or exited. As a result, we recognized undeveloped leasehold impairment expense of $62 million primarily attributable to Gulf of
Mexico leases. We recorded leasehold impairment expense of $93 million in 2016 and $21 million in 2015. This expense is
included in exploration expense in the consolidated statements of operations.
Note 7. Equity Method Investments
Equity Method Investments Investments accounted for under the equity method consist primarily of the following:
•
•
•
•
•
50% interest in Advantage Pipeline, which owns and operates a 70-mile crude oil pipeline in Texas (See Note 4 –
Acquisitions, Divestitures and Merger);
50% interest in CONE Gathering, which owns and operates natural gas gathering facilities servicing the Marcellus Shale
(See Note 4 – Acquisitions, Divestitures and Merger);
34% interest in CONE Midstream, a public master limited partnership, which constructs, owns and operates natural gas
gathering and other midstream energy assets in the Marcellus Shale;
45% interest in Atlantic Methanol Production Company, LLC (AMPCO), which owns and operates a methanol plant
and related facilities in Equatorial Guinea; and
28% interest in Alba Plant LLC (Alba Plant), which owns and operates a liquefied petroleum gas (LPG) processing
plant in Equatorial Guinea.
CONE Midstream Dropdown Transaction In fourth quarter 2016, CONE Midstream completed an acquisition of midstream
assets (dropdown) from CONE Gathering. CONE Gathering subsequently distributed $70 million cash and additional CONE
Midstream common units to us.
Equity method investments are as follows:
(millions)
Equity Method Investments
CONE Investments(1)
AMPCO
Alba Plant
Advantage Pipeline
Other
Total Equity Method Investments
December 31,
2017
2016
$
$
— $
129
80
70
26
305
$
172
120
82
—
26
400
(1) CONE Investments include CONE Midstream and CONE Gathering. The investments are included in assets held for sale at December 31,
2017.
Other At December 31, 2017, consolidated retained earnings included $90 million related to the undistributed earnings of equity
method investees.
The carrying value of our AMPCO investment was $12 million higher than the underlying net assets of the investee at
December 31, 2017. The difference is related to capitalized interest which is being amortized into earnings over the remaining
useful life of the plant.
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Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Summarized, 100% combined financial information for equity method investees is as follows:
(millions)
Balance Sheet Information
Current Assets
Noncurrent Assets
Current Liabilities
Noncurrent Liabilities
(millions)
Statements of Operations Information
Operating Revenues
Operating Expenses
Operating Income
Other (Income) Net
Income Before Income Taxes
Income Tax Provision
Net Income
December 31,
2017
2016
$
$
390
588
171
90
313
1,390
149
256
Year Ended December 31,
2016
2015
2017
$
$
790
303
487
(15)
502
136
366
$
$
667
355
312
(7)
319
60
259
$
$
645
393
252
(9)
261
46
215
Note 8. Derivative Instruments and Hedging Activities
Objective and Strategies for Using Derivative Instruments We may 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. The derivative instruments we use may
include variable to fixed price commodity swaps, enhanced swaps, two-way and three-way collars, basis swaps and/or put
options.
The fixed price swap and two-way collar contracts entitle us (floating price payor) to receive settlement from the counterparty
(fixed price payor) for each calculation period in amounts, if any, by which the settlement price for the scheduled trading days
applicable for each calculation period is less than the fixed strike price or floor price. We would pay the counterparty if the
settlement price for the scheduled trading days applicable for each calculation period is more than the fixed strike price or
ceiling price. The amount payable by us, if the floating price is above the fixed or ceiling price, is the product of the notional
quantity per calculation period and the excess of the floating price over the fixed or ceiling price in respect of each calculation
period. The amount payable by the counterparty, if the floating price is below the fixed or floor price, is the product of the
notional quantity per calculation period and the excess of the fixed or floor price over the floating price in respect of each
calculation period.
A three-way collar consists of a two-way collar contract combined with a put option contract sold by us with a strike price
below the floor price of the two-way collar. We receive price protection at the purchased put option floor price of the two-way
collar if commodity prices are above the sold put option strike price. If commodity prices fall below the sold put option strike
price, we receive the cash market price plus the delta between the two put option strike prices. This type of instrument allows us
to capture more value in a rising commodity price environment, but limits our benefits in a downward commodity price
environment.
For put options, we typically pay a premium to the counterparty in exchange for the sale of the instrument. If the index price is
below the floor price of the put option, we receive the difference between the floor price and the index price multiplied by the
contract volumes less the option premium at the time of settlement. If the index price settles at or above the floor price of the
put option, we pay only the put option premium at the time of settlement. We had no outstanding put options as of December
31, 2017.
While these instruments mitigate the cash flow risk of future reductions in commodity prices, they may also curtail benefits
during periods of increasing commodity prices.
See Note 13. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair
values of our derivative instruments.
116
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Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Counterparty Credit Risk Derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments
are currently with a diversified group of major banks or market participants, and we monitor and manage our level of financial
exposure. Our commodity derivative contracts are executed under master agreements which allow us, in the event of default, to
elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and
liability positions with the defaulting counterparty would be net settled at the time of election.
We monitor the creditworthiness of our commodity derivatives counterparties. However, we are not able to predict sudden
changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability
to mitigate an increase in counterparty credit risk.
Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative
contracts resulting in a cash settlement. Should one of these financial counterparties not perform, we may not realize the benefit
of some of our derivative instruments under lower commodity prices and could incur a loss.
Unsettled Derivative Instruments As of December 31, 2017, we had entered into the following crude oil derivative instruments:
Settlement
Period
2018
2018
2018
2018
2018
2018
2018
2018
2019
2019
2019
2019
Type of Contract
Three-Way Collars
Swaps
Two-Way Collars
Three-Way Collars
Swaps
Two-Way Collars
Three-Way Collars
Basis Swaps
Swaps
Swaps
Three-Way Collars
Basis Swaps
Index
NYMEX WTI
NYMEX WTI
NYMEX WTI
Dated Brent
ICE Brent
ICE Brent
ICE Brent
(1)
NYMEX WTI
ICE Brent
ICE Brent
(1)
Swaps
Collars
Weighte
d
Average
Fixed
Price
Weighte
d
Average
Short
Put
Price
Weighte
d
Average
Floor
Price
Weighte
d
Average
Ceiling
Price
Bbls Per
Day
10,000
$
— $ 45.50 $ 52.50 $ 69.09
24,000
18,000
3,000
2,000
2,000
5,000
12,000
3,000
5,000
3,000
12,000
57.09
—
—
59.00
—
—
(0.60)
55.07
57.00
—
(1.01)
—
—
— 50.42
40.00
50.00
—
—
— 50.00
43.00
50.00
—
—
—
—
—
—
—
58.82
70.41
—
55.25
59.50
—
—
—
43.00
50.00
64.07
—
—
—
(1) We have entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing,
Oklahoma. The weighted average differential represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes
covered by the basis swap contracts.
As of December 31, 2017, we had entered into the following natural gas derivative instruments:
Settlement
Period
2018
Type of Contract
Three-Way Collars
Index
MMBtu
Per Day
Weighted
Average
Short Put
Price
Collars
Weighted
Average
Floor
Price
Weighted
Average
Ceiling
Price
NYMEX HH
120,000 $
2.50 $
2.88 $
3.65
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Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Fair Value Amounts and Gains and Losses on Derivative Instruments The fair values of derivative instruments in our consolidated
balance sheets were as follows:
Fair Value of Derivative Instruments (1)
Asset Derivative Instruments
Liability Derivative Instruments
December 31,
2017
December 31,
2016
December 31,
2017
December 31,
2016
Balance
Sheet
Location
Fair
Value
Balance
Sheet
Location
Fair
Value
Balance
Sheet
Location
Fair
Value
Balance
Sheet
Location
Fair
Value
(millions)
Commodity
Derivative
Instruments
Total
Current
Assets
Noncurrent
Assets
$
$
Current
Assets
Noncurrent
Assets
2
—
2
$
$
Current
Liabilities
Noncurrent
Liabilities
—
—
—
$
$
Current
Liabilities
Noncurrent
Liabilities
58
15
73
$
$
102
14
116
(1) See Note 1. Summary of Significant Accounting Policies – Derivative Instruments and Hedging Activities for a discussion of our netting
policy.
The effect of derivative instruments on our consolidated statements of operations was as follows:
(millions)
Cash (Received) Paid in Settlement of Commodity Derivative Instruments
Crude Oil
Natural Gas
NGLs (1)
Total Cash Received in Settlement of Commodity Derivative Instruments
Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments
Crude Oil
Natural Gas
NGLs (1)
Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments
(Gain) Loss on Commodity Derivative Instruments
Crude Oil
Natural Gas
NGLs (1)
Total (Gain) Loss on Commodity Derivative Instruments
Year Ended December 31,
2016
2015
2017
$
$
(14) $
1
—
(13)
18
(68)
—
(50)
4
(67)
—
(63) $
(499) $
(70)
—
(569)
(844)
(147)
(18)
(1,009)
582
126
—
708
83
56
—
139
$
423
65
20
508
(421)
(82)
2
(501)
(1) Amounts for NGLs relate to commodity derivative instruments, acquired in the Rosetta Merger, which expired as of December 31, 2015.
118
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Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 9. Asset Retirement Obligations
Asset retirement obligations (AROs) consist primarily of estimated costs of dismantlement, removal, site reclamation and
similar activities associated with our oil and gas properties. Changes in AROs were as follows:
(millions)
Asset Retirement Obligations, Beginning Balance
Liabilities Incurred
Liabilities Settled
Revision of Estimate
Reclassification to Liabilities Associated with Assets Held for Sale
Accretion Expense
Asset Retirement Obligations, Ending Balance
Year Ended December 31,
2017
2016
$
$
935
94
(82)
(65)
(54)
47
875
$
$
989
21
(120)
(3)
—
48
935
Year Ended December 31, 2017 Liabilities incurred include $63 million related to the Clayton Williams Energy Acquisition
and $31 million primarily for other US onshore wells and midstream facilities placed into service.
Liabilities settled include $43 million related to abandonment of US onshore properties, $19 million related to properties sold in
the Greeley Crescent (DJ Basin) acreage divestiture, $12 million related to properties sold in the Marcellus Shale upstream
divestiture and $8 million related to other offshore domestic and international properties.
Revisions of estimates include a $42 million decrease related to changes in cost and timing associated with the North Sea
abandonment project and a $38 million decrease for US onshore and Gulf of Mexico properties, partially offset by an increase
of $15 million for West Africa.
In 2017, we also transferred $42 million and $12 million of ARO liabilities associated with Southwest Royalties and Tamar
field, offshore Israel, respectively, to liabilities associated with assets held for sale. Refer to Item 8. Financial Statements and
Supplementary Data - Note 4. Acquisitions, Divestitures and Merger.
Year Ended December 31, 2016 Liabilities incurred were due to new wells and facilities placed into service for US onshore,
Gulf of Mexico, and offshore Israel.
Liabilities settled were related to wells and facilities permanently abandoned at the end of their useful lives and to assets sold.
Settlements included $65 million related to abandonment of Gulf of Mexico properties, $49 million related to US onshore
properties abandoned or sold, $5 million related to offshore Israel properties and $1 million related to the North Sea.
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Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 10. Long-Term Debt
Our debt consists of the following:
(millions, except percentages)
Revolving Credit Facility, due August 27, 2020
Noble Midstream Services Revolving Credit Facility,
due September 20, 2021
Term Loan Facility, due January 6, 2019 (1)
Leviathan Term Loan Facility, due February 23, 2025
Senior Notes, due March 1, 2019 (2)
Senior Notes, due May 1, 2021
Senior Notes, due December 15, 2021
Senior Notes, due June 1, 2022 (1)
Senior Notes, due October 15, 2023
Senior Notes, due November 15, 2024
Senior Notes, due April 1, 2027
Senior Notes, due January 15, 2028 (2)
Senior Notes, due March 1, 2041
Senior Notes, due November 15, 2043
Senior Notes, due November 15, 2044
Senior Notes, due August 15, 2047 (2)
Other Senior Notes and Debentures (3)
Capital Lease and Other Obligations (4)
Total
Unamortized Discount
Unamortized Premium (2)
Unamortized Debt Issuance Costs
Total Debt, Net of Discount
Less Amounts Due Within One Year
Capital Lease and Other Obligations
Long-Term Debt Due After One Year
December 31,
2017
December 31,
2016
Debt
Interest Rate
Debt
Interest Rate
—%
—%
2.01%
—
8.25%
5.63%
4.15%
5.88%
7.25%
3.90%
8.00%
—%
6.00%
5.25%
5.05%
—%
7.13%
—%
$
230
2.27%
$
—
85
—
—
—
379
1,000
—
100
650
250
600
850
1,000
850
500
92
273
6,859
(24)
12
(40)
6,807
(61)
6,746
$
$
$
2.49%
—%
—%
—%
5.63%
4.15%
—%
7.25%
3.90%
8.00%
3.85%
6.00%
5.25%
5.05%
4.95%
7.13%
—%
$
$
$
—
550
—
1,000
379
1,000
18
100
650
250
—
850
1,000
850
—
92
375
7,114
(23)
17
(34)
7,074
(63)
7,011
(1)
(2)
(3)
In fourth quarter 2017, we repaid $550 million of borrowings under the Term Loan Facility and $18 million of our outstanding Senior
Notes due June 1, 2022.
In third quarter 2017, we redeemed all of our Senior Notes due March 1, 2019 and issued Senior Notes due January 15, 2028 and August
15, 2047.
Includes $8 million of Senior Notes due June 1, 2024 and $84 million of Senior Debentures due August 1, 2097. The weighted average
interest rate for these instruments is 7.13%.
(4) The reduction from 2016 includes $41 million related to other obligations for drilling commitments assumed by the acquirer of the
Marcellus Shale upstream assets and $60 million of capital lease principal payments.
All of our long-term debt is senior unsecured debt and is, therefore, pari passu with respect to the payment of both principal
and interest. The indenture documents of each of our notes provide that we may prepay the instruments by creating a
defeasance trust. The defeasance provisions require that the trust be funded with securities sufficient, in the opinion of a
nationally recognized accounting firm, to pay all scheduled principal and interest due under the respective agreements. Interest
on each of these issues is payable semi-annually.
Revolving Credit Facility Our Revolving Credit Facility (i) provides for facility fee rates that range from 10 basis points to 25
basis points per year depending upon our credit rating, (ii) includes sub-facilities for short-term loans and letters of credit up to
an aggregate amount of $500 million under each sub-facility and (iii) provides for interest rates that are based upon the
Eurodollar rate plus a margin that ranges from 90 basis points to 150 basis points depending upon our credit rating.
120
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Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
The Revolving Credit Facility requires that our total debt to capitalization ratio (as defined in the Revolving Credit Facility),
expressed as a percentage, not exceed 65% at any time. A violation of this covenant could result in a default under the Credit
Agreement, which would permit the participating banks to restrict our ability to access the Revolving Credit Facility and
require the immediate repayment of any outstanding advances under the Revolving Credit Facility. As of December 31, 2017,
we were in compliance with our debt covenants.
The Revolving Credit Facility is available for general corporate purposes. Certain lenders that are a party to the Revolving
Credit Facility have in the past performed, and may in the future from time to time perform, investment banking, financial
advisory, lending or commercial banking services for us for which they have received, and may in the future receive, customary
compensation and reimbursement of expenses.
Noble Midstream Services Revolving Credit Facility On September 20, 2016, Noble Midstream Services LLC (Noble
Midstream Services), a subsidiary of Noble Midstream Partners, entered into a credit agreement for a $350 million revolving
credit facility (Noble Midstream Services Revolving Credit Facility). The Noble Midstream Services Revolving Credit Facility
has a five year maturity and includes a letter of credit sublimit of up to $100 million for issuances of letters of credit. The
borrowing capacity on the Noble Midstream Services Revolving Credit Facility may be increased by an additional $350
million, subject to certain conditions, and is available to fund working capital and to finance acquisitions and other capital
expenditures of Noble Midstream Partners.
Borrowings by Noble Midstream Services under the Noble Midstream Services Revolving Credit Facility bear interest at a rate
equal to an applicable margin plus, at Noble Midstream Service's option, either:
•
•
in the case of base rate borrowings, a rate equal to the highest of (1) the prime rate, (2) the greater of the federal funds
rate or the overnight bank funding rate, plus 0.5% and (3) the London interbank offered rate (LIBOR) for an interest
period of one month plus 1.00%; or
in the case of LIBOR borrowings, the offered rate per annum for deposits of dollars for the applicable interest period.
The Noble Midstream Services Revolving Credit Facility includes certain financial covenants as of the end of each fiscal
quarter, including a (1) consolidated leverage ratio to consolidated adjusted earnings before interest expense, income taxes,
depreciation, depletion, and amortization (EBITDA) and (2) consolidated interest coverage ratio (each covenant as described in
the Noble Midstream Services Revolving Credit Facility). All obligations of Noble Midstream Services, as the borrower under
the Noble Midstream Services Revolving Credit Facility, are guaranteed by Noble Midstream Partners and all wholly-owned
material subsidiaries of Noble Midstream Partners. Debt issuance costs associated with this facility were de minimis.
On January 31, 2018, in connection with the acquisition of Saddle Butte, Noble Midstream Partners drew an additional $300
million under the Noble Midstream Services Revolving Credit Facility and partially exercised the accordion feature, increasing
the commitments under the credit agreement to $530 million.
Senior Notes Issuance and Completed Tender Offer On August 15, 2017, we issued $600 million of 3.85% senior unsecured
notes that will mature on January 15, 2028 and $500 million of 4.95% senior unsecured notes that will mature on August 15,
2047. Interest on the 3.85% senior notes and 4.95% senior notes is payable semi-annually beginning January 15, 2018 and
February 15, 2018, respectively. We may redeem some or all of the senior notes at any time at the applicable redemption price,
plus accrued interest, if any. The senior notes were issued at a discount of $4 million and debt issuance costs incurred totaled
$11 million, both of which are reflected as a reduction of long-term debt and are amortized over the life of the notes. Proceeds
of $1 billion from the issuance of senior notes were used solely to fund the tender offer and the redemption of $1 billion of our
8.25% senior notes due March 1, 2019. As a result, we paid a premium of $96 million to the holders of the 8.25% senior notes
and recognized a loss of $98 million in third quarter 2017, which is reflected in other non-operating (income) expense in our
consolidated statements of operations.
Leviathan Term Loan Facility On February 24, 2017, Noble Energy Mediterranean Ltd. (NEML), a wholly-owned subsidiary
of Noble Energy, entered into a facility agreement (Leviathan Term Loan Facility) which provides for a limited recourse
secured term loan facility with an aggregate principal borrowing amount of up to $1.0 billion, of which $625 million is initially
committed. Any amounts borrowed under the Leviathan Term Loan Facility will be available to fund a portion of our share of
costs for the initial phase of development of the Leviathan field offshore Israel.
Any amounts borrowed will be subject to repayment on a quarterly basis following production startup for the first phase of
development, which is targeted for the end of 2019. Repayment will be in accordance with an amortization schedule set forth in
the facility agreement, with a final balloon payment of no more than 35% of the loans outstanding. The Leviathan Term Loan
Facility matures on February 23, 2025 and we can prepay borrowings at any time, in whole or in part, without penalty. The
Leviathan Term Loan Facility contains customary representations and warranties, affirmative and negative covenants, and
121
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Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
events of default and also includes a prepayment mechanism that reduces the final balloon amount if cash flows exceed certain
defined coverage ratios.
Any amounts borrowed will accrue interest at LIBOR, plus a margin of 3.50% per annum prior to production startup, 3.25%
during the period following production startup until the last two years of maturity, and 3.75% during the last two years until the
maturity date. We are also required to pay a commitment fee equal to 1.00% per annum on the unused and available
commitments under the Leviathan Term Loan Facility until the beginning of the repayment period.
The Leviathan Term Loan Facility is secured by a first priority security interest in substantially all of NEML's interests in the
Leviathan field and its marketing subsidiary, and in assets related to the initial phase of the project. All of NEML’s revenues
from the first phase of Leviathan development will be deposited in collateral accounts, and we will be required to maintain a
debt service reserve account for the benefit of the lenders under the Leviathan Term Loan Facility. Once servicing accounts are
replenished and debt service made, all remaining cash will be available to us and our subsidiaries.
Term Loan Facility and Completed Tender Offers On January 6, 2016, we entered into a term loan agreement (Term Loan
Facility), which provided for a three-year term loan facility for a principal amount of $1.4 billion. Provisions of the Term Loan
Facility were consistent with those in the Revolving Credit Facility. Borrowings under the Term Loan Facility could be prepaid
prior to maturity without premium. The Term Loan Facility accrued interest, at our option, at either (a) a base rate equal to the
highest of (i) the rate announced by Citibank, N.A., as its prime rate, (ii) the Federal Funds Rate plus 0.5%, and (iii) a LIBOR
plus 1.0%, plus a margin that ranged from 10 basis points to 75 basis points depending upon our credit rating, or (b) a LIBOR,
plus a margin that ranged from 100 basis points to 175 basis points depending upon our credit rating.
Borrowings under the Term Loan Facility were used solely to fund tender offers for approximately $1.38 billion of notes
assumed in the Rosetta Merger in 2015. As a result of the tender offers, we recognized a gain of $80 million in first quarter
2016 which is reflected in other non-operating (income) expense in our consolidated statements of operations. In fourth quarter
2016, we prepaid $850 million of the amount outstanding under the Term Loan Facility from cash on hand. In fourth quarter
2017, we repaid the remaining outstanding balance of $550 million under this facility using proceeds received from the sale of
non-core Greeley Crescent and Bronco acreage in the DJ Basin.
Fair Value of Debt See Note 13. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used
to estimate the fair values of debt.
Capital Lease and Other Obligations The amount of the capital lease obligation is based on the discounted present value of
future minimum lease payments, and therefore does not reflect future cash lease payments. Amounts due within one year equal
the amount by which the capital lease obligation is expected to be reduced during the next 12 months. See Note 17.
Commitments and Contingencies for future capital lease payments.
Annual Debt Maturities Annual maturities of outstanding debt, excluding capital lease payments, as of December 31, 2017 are
as follows:
(millions)
2018
2019
2020
2021
2022
Thereafter
Total
Debt
Principal
Payments
$
$
—
—
230
1,464
—
4,892
6,586
Note 11. Income Taxes
Recent Changes in US Tax Law On December 22, 2017, the US Congress enacted the Tax Reform Legislation, which made
significant changes to US federal income tax law, including a reduction in the federal corporate tax rate to 21% effective
January 1, 2018. Under US GAAP, we are required to recognize the effect of a rate change on deferred tax assets and liabilities
in the period in which the tax rate change is enacted. Therefore, the rate change enacted by the Tax Reform Legislation resulted
in the recognition of a deferred tax benefit of $500 million at December 31, 2017.
Further, the Tax Reform Legislation provides for a transition tax (toll tax) on a one-time “deemed repatriation” of accumulated
foreign earnings for the year ended December 31, 2017. Based on current interpretations of the law, we have recognized
additional taxable income of $767 million associated with the transition tax, which is fully offset by current year net operating
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Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
losses and have recorded corresponding deemed foreign tax credits of $164 million, against which we have recorded a full
valuation allowance.
The Tax Reform Legislation also repealed corporate alternative minimum tax (AMT) for tax years beginning January 1, 2018,
and provides that existing AMT credit carryovers are refundable beginning in 2018. We have approximately $3 million of AMT
credit carryovers that are expected to be fully refunded by 2022.
In addition, the Tax Reform Legislation preserves deductibility of intangible drilling costs and provides for 100% bonus
depreciation on tangible personal property expenditures through 2022. The bonus depreciation percentage is phased down from
100% beginning in 2023 to 0% for years after 2026.
The Tax Reform Legislation is a comprehensive bill containing other provisions, such as limitations on the deductibility of
interest expense and certain executive compensation, that are not expected to materially affect us. The ultimate impact of the
Tax Reform Legislation may differ from our estimates due to changes in interpretations and assumptions made by us, as well as
additional regulatory guidance that may be issued. In particular, our estimate of the impact of the toll tax is a provisional
amount, based on current legal interpretations. This amount may be adjusted in future periods, as an adjustment to income tax
expense or benefit, in the period in which the final amounts are determined.
Income Tax Disclosures
Components of income (loss) from operations before income taxes are as follows:
Year Ended December 31,
2016
2015
2017
(2,831) $
640
(2,191) $
(1,859) $
87
(1,772) $
(2,338)
119
(2,219)
Year Ended December 31,
2016
2015
2017
$
$
$
$
$
(11)
1
96
86
(1,258)
(8)
39
(1,227)
(1,141)
52.1%
$
$
$
$
$
(4)
5
196
197
(784)
(24)
(176)
(984)
(787)
44.4%
(1)
—
107
106
216
(5)
(95)
116
222
(10.0)%
(millions)
Domestic
Foreign
Total
The income tax provision (benefit) consists of the following:
(millions)
Current Taxes
Federal
State
Foreign
Total Current
Deferred Taxes
Federal
State
Foreign
Total Deferred
Total Income Tax (Benefit) Provision Attributable to Noble Energy
Effective Tax Rate
$
$
$
$
$
$
$
123
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Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
A reconciliation of the federal statutory tax rate to the effective tax rate is as follows:
(percentages)
Federal Statutory Rate (1)
Effect of
Earnings of Equity Method Investees
Noncontrolling Interests
US and Foreign Statutory Rate Change (1)
Transition Tax (1)
State Taxes, Net of Federal Benefit
Difference Between US and Foreign Rates
Foreign Exploration Loss
Change in Valuation Allowance (1)
Oil Profits Tax - Israel
Tax Contingency
Accumulated Undistributed Foreign Earnings (1)
Goodwill Impairment
Other, Net
Effective Rate
Year Ended December 31,
2016
2015
2017
35.0%
35.0%
35.0 %
1.9
1.1
23.5
(4.8)
0.3
1.8
—
(17.4)
(0.1)
0.1
11.0
—
(0.3)
52.1%
1.0
0.4
1.6
—
1.3
(0.1)
0.1
(2.0)
—
0.2
7.2
—
(0.3)
44.4%
0.6
—
—
—
0.3
2.6
2.7
—
0.1
0.4
(37.7)
(12.3)
(1.7)
(10.0)%
(1) See Recent Changes in US Tax Law, above. Rate will decrease to 21.0% for fiscal year 2018. In addition, see discussion regarding
accumulated undistributed foreign earnings above.
Deferred tax assets and liabilities resulted from the following:
(millions)
Deferred Tax Assets
Loss Carryforwards
Employee Compensation and Benefits
Mark to Market of Commodity Derivative Instruments
Foreign Tax Credits
Other
Total Deferred Tax Assets
Valuation Allowance - Foreign Loss Carryforwards and Foreign Tax Credits
Net Deferred Tax Assets
Deferred Tax Liabilities
Accumulated Undistributed Foreign Earnings (1)
Property, Plant and Equipment, Principally Due to Differences in Depreciation, Amortization,
Lease Impairment and Abandonments
Total Deferred Tax Liability
Net Deferred Tax Liability
December 31,
2017
2016
$
$
$
$
$
$
$
$
902
97
7
366
104
1,476
(549)
927
—
474
150
44
—
49
717
(242)
475
(240)
(2,029)
(2,029) $
(1,102) $
(2,054)
(2,294)
(1,819)
(1) At December 31, 2017, we reversed the deferred tax liability associated with the removal of the assertion of indefinitely reinvested
earnings, resulting in recognition of a deferred tax benefit of $240 million.
Net deferred tax assets and liabilities were classified in the consolidated balance sheets as follows:
(millions)
Deferred Income Tax Asset - Noncurrent
Deferred Income Tax Liability - Noncurrent
Net Deferred Tax Liability
124
December 31,
2017
2016
$
$
$
25
(1,127)
(1,102) $
—
(1,819)
(1,819)
Table of Contents
Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Deferred Tax Assets Our estimated US federal income tax net operating loss (NOL) carryforwards totaled approximately $3.2
billion at December 31, 2017. Included in the resulting deferred tax assets are acquired NOLs associated with the Clayton
Williams Energy Acquisition in 2017 and the Rosetta Merger in 2015.
In assessing the realizability of deferred tax assets, we consider whether it is more likely than not that some portion or all of the
deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future
taxable income in the appropriate tax jurisdictions during the periods in which those temporary differences become deductible.
We consider the scheduled reversal of deferred tax liabilities, current financial position, results of operations, projected future
taxable income and tax planning strategies as well as current and forecasted business economics in the oil and gas industry.
Based on the level of historical taxable income and projections for future taxable income, we believe it is more likely than not
that we will realize the benefits of these NOL carryforwards. However, the amount of the deferred tax assets considered
realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced.
We currently have a valuation allowance on the deferred tax assets associated with foreign loss carryforwards and foreign tax
credits. The valuation allowance on foreign loss carryforwards totaled $183 million in 2017 and $242 million in 2016. The
changes to the valuation allowance for the loss carryforwards between periods was attributable to the offset of the valuation
allowance against the NOL in a jurisdiction in which we are no longer active. Deemed foreign tax credits of $164 million were
recognized along with the additional taxable income associated with the transition tax. A full valuation allowance of $366
million has been recorded against all foreign tax credits based on current interpretation of the Tax Reform Legislation and the
expected future utilization of NOL carryforwards.
Clayton Williams Energy Acquisition On April 24, 2017, we completed the Clayton Williams Energy Acquisition. For federal
income tax purposes, the transaction qualified as a tax free merger and we acquired carryover tax basis in Clayton Williams
Energy's assets and liabilities. After the fair market valuation, we have currently recorded an opening balance sheet deferred tax
liability of $307 million, adjusted for the new US statutory tax rate, which includes a deferred tax asset for federal pre-tax net
operating losses of approximately $450 million. The merger resulted in a change of control for federal income tax purposes, and
the NOL usage will be subject to an annual limitation in part based on Clayton Williams Energy's value at the date of the
merger. We anticipate full utilization of the total NOL prior to expiration.
Accumulated Undistributed Earnings of Foreign Subsidiaries In 2015, we changed our indefinite reinvestment assertion (APB
23 assertion) based on the continued and prolonged decline in global commodity prices and an evaluation of our operations’
anticipated capital requirements and projected foreign cash positions given the adoption of the Israel Natural Gas Framework in
December 2015.
During 2016, we reviewed capital requirements and foreign cash positions, and reduced the deferred tax liability associated
with unremitted earnings, net of foreign tax credits, to $240 million as of December 31, 2016.
In 2017, as a result of Tax Reform Legislation, which establishes a new territorial tax regime, the deferred tax liability recorded
as of December 31, 2016 was reversed, resulting in a deferred tax benefit of $240 million for the year ended December 31,
2017. We do not expect a withholding tax impact upon actual distribution of earnings and as such have not recorded any
additional tax associated with the unremitted earnings.
Effective Tax Rate Our effective tax rate increased in 2017 as compared with 2016 primarily due to the recognition of a
deferred tax benefit related to the Tax Reform Legislation. The deferred tax benefit resulted from the revaluation of the ending
deferred tax liability at the reduced future tax rate and the transition to the new territorial tax regime.
Our effective tax rate increased in 2016 as compared with 2015 primarily due to adjustments to deferred taxes for removal of
the APB 23 assertion, as noted above, decreased earnings in foreign jurisdictions with rates that vary from the US statutory rate,
a decrease in the Israeli income tax rate, and the 2015 impact of foreign dividend repatriation and goodwill impairment.
Israeli Tax Law Effective December 21, 2016, the Israeli government decreased the corporate income tax rate from 25% to
24% for 2017 and announced a further rate decrease from 24% to 23% effective January 2018. The change decreased the
deferred tax expense for 2017 by $12 million.
Furthermore, our Israeli operations are subject to the Natural Resources Profits Taxation Law, 2011 (the Law), which imposes a
separate additional tax on profits from oil and gas activities (Profits Tax). The Profits Tax is calculated by dividing net
accumulated revenue generated by each separate project by its cumulative investments as defined within the Law. Once the
revenue factor (R Factor) reaches 1.5, a tax rate of 20% is imposed; as the ratio increases to a maximum of 2.3, the Profits Tax
increases progressively up to a maximum rate of 50%. The Profits Tax provides for a corporate tax rate adjustment based on the
corporate income tax rate, which is currently 23%. To the extent the corporate income tax rate exceeds 18%, a reduction in the
Profits Tax rate is calculated. At the current corporate tax rate, the Profits Tax rate is 46.8%. The Profits Tax is deductible for
corporate Israeli tax purposes. Our Tamar and Leviathan projects are both subject to the Profits Tax and are expected to pay at
the maximum rate.
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Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Unrecognized Tax Benefits We file a consolidated income tax return in the US federal jurisdiction, and we file income tax
returns in various states and foreign jurisdictions. Our income tax returns are routinely audited by the applicable revenue
authorities, and provisions are made in the financial statements for differences between positions taken in tax returns and
amounts recognized in the financial statements in anticipation of audit results.
In our major tax jurisdictions, the earliest years remaining open to examination are: US - 2014, Israel - 2015 and Equatorial
Guinea - 2012.
Our policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense.
A reconciliation of our beginning and ending amounts of unrecognized tax benefits follows:
(millions)
Unrecognized Tax Benefits, Beginning Balance
Reductions for Tax Positions of Prior Years
Unrecognized Tax Benefits, Ending Balance
Twelve Months Ended
December 31, 2017
$
$
3
(3)
—
The changes to our unrecognized tax benefits during 2017 primarily resulted from changes in various foreign tax return filings,
positions and audit settlements. The adjustments to our reserves for uncertain tax positions had a de minimis impact on our net
income.
During 2017, we recognized and accrued a de minimis amount of interest and no penalties.
Note 12. Stock-Based and Other Compensation Plans
We recognized total stock-based compensation expense as follows:
(millions)
Stock-Based Compensation Expense Included in:
General and Administrative Expense
Exploration Expense and Other
Total Stock-Based Compensation Expense
Tax Benefit Recognized
Year Ended December 31,
2016
2015
2017
$
$
$
$
56
48
104
$
(36) $
$
62
15
77
$
(27) $
50
36
86
(30)
Stock Option and Restricted Stock Plans Our stock option and restricted stock plans are described below.
2017 Long-Term Incentive Plan On April 25, 2017, our stockholders approved the Noble Energy, Inc. 2017 Long-Term
Incentive Plan (the 2017 Plan). Upon stockholder approval, the 2017 Plan superceded and replaced the Noble Energy, Inc. 1992
Stock Option and Restricted Stock Plan, as amended (the 1992 Plan) which was frozen so that no future grants would be made
under the 1992 Plan. The 1992 Plan continues to govern awards that were outstanding as of the date of its suspension, which
remain in effect pursuant to their terms. Under the 2017 Plan, the Compensation, Benefits and Stock Option Committee of the
Board of Directors (the Committee) may grant stock options, stock appreciation rights, restricted stock, restricted stock units,
performance awards, stock awards and other incentive awards to our officers or other employees and those of our subsidiaries.
The maximum number of shares that may be granted under the 2017 Plan is 29 million shares of common stock. At December
31, 2017, 28,987,609 shares of our common stock were reserved for issuance, including 28,972,832 shares available for future
grants and awards, under the 2017 Plan.
Stock options are issued with an exercise price equal to the fair market value of our common stock on the date of grant, and are
subject to such other terms and conditions as may be determined by the Committee. Unless granted by the Committee for a
shorter term, the options expire 10 years from the grant date. Option grants generally vest ratably over a three-year period.
Restricted stock awards made under the 2017 Plan are subject to such restrictions, terms and conditions, including forfeitures, if
any, as may be determined by the Committee. During the period in which such restrictions apply, unless specifically provided
otherwise in accordance with the terms of the 2017 Plan, the recipient of restricted stock would be the record owner of the
shares and have all the rights of a stockholder with respect to the shares, including the right to vote and the right to receive
dividends or other distributions made or paid with respect to the shares. The dividends or other distributions pertaining to the
restricted shares will be held by the Company until the restriction period ends and the shares vest or forfeit. If the restricted
shares forfeit, then the recipient shall not be entitled to receive the dividend or distribution, which will transfer to the Company.
Restricted stock awards with a time-vested restriction vest over a two or three-year period. Performance share awards cliff vest
after a three-year period if the Company achieves certain levels of total shareholder return relative to a pre-determined industry
peer group.
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Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
2015 Stock Plan for Non-Employee Directors The 2015 Stock Plan for Non-Employee Directors of Noble Energy, Inc., as
amended (the 2015 Plan) provides for grants of stock options and awards of restricted stock to our non-employee directors. The
2015 Plan superseded and replaced the 2005 Stock Plan for Non-Employee Directors of Noble Energy, Inc. The total number of
shares of our common stock that may be issued under the 2015 Plan is 708,996. At December 31, 2017, 674,025 shares of our
common stock were reserved for issuance, including 463,096 shares available for future grants and awards, under the 2015
Plan.
Stock Option Grants The fair value of each stock option granted is estimated on the date of grant using a Black-Scholes-
Merton option valuation model that used the assumptions described below:
• Expected term The expected term represents the period of time that options granted are expected to be outstanding,
which is the grant date to the date of expected exercise or other expected settlement for options granted. The
hypothetical midpoint scenario we use considers our actual exercise and post-vesting cancellation history and
expectations for future periods, which assumes that all vested, outstanding options are settled halfway between the
current date and their expiration date.
• Expected volatility The expected volatility represents the extent to which our stock price is expected to fluctuate
between the grant date and the expected term of the award. We use the historical volatility of our common stock for a
period equal to the expected term of the option prior to the date of grant. We believe that historical volatility produces an
estimate that is representative of our expectations about the future volatility of our common stock over the expected
term.
• Risk-free rate The risk-free rate is the implied yield available on US Treasury securities with a remaining term equal to
the expected term of the option. We base our risk-free rate on a weighting of five and seven year US Treasury securities
as of the date of grant.
• Dividend yield The dividend yield represents the value of our stock’s annualized dividend as compared to our stock’s
average price for the three-year period ended prior to the date of grant. It is calculated by dividing one full year of our
expected dividends by our average stock price over the three-year period ended prior to the date of grant.
The assumptions used in valuing stock options granted were as follows:
(weighted averages)
Expected Term (in Years)
Expected Volatility
Risk-Free Rate
Expected Dividend Yield
Weighted Average Grant-Date Fair Value
Stock option activity was as follows:
Outstanding at December 31, 2016
Granted
Exercised
Forfeited
Outstanding at December 31, 2017
Exercisable at December 31, 2017
Year Ended December 31,
2016
2015
2017
6.4
33.2%
2.2%
0.9%
6.3
32.4%
1.6%
0.7%
6.0
32.6%
1.4%
1.2%
$
13.26
$
10.10
$
13.93
Weighted
Average
Exercise
Price
(per share)
43.49
$
39.40
37.57
43.93
43.42
44.98
$
$
Options
15,088,862
1,819,819
(382,882)
(976,577)
15,549,222
12,101,890
Weighted
Average
Remaining
Contractual
Term
(in years)
Aggregate
Intrinsic
Value
(in millions)
5.0
4.0
$
$
6
6
The total intrinsic value of options exercised was $4 million in 2017, $10 million in 2016 and $7 million in 2015. As of
December 31, 2017, $21 million of compensation cost related to unvested stock options granted under the Plans remained to be
recognized. The cost is expected to be recognized over a weighted-average period of 1.3 years. We issue new shares of our
common stock to settle option exercises. Dividends are not paid on unexercised options.
127
Table of Contents
Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Restricted Stock Awards Awards of time-vested restricted stock (shares subject to service conditions) are valued at the price
of our common stock at the date of award. The fair value of the market based restricted stock awards was estimated on the date
of award using a Monte Carlo valuation model that uses the assumptions in the following table. The Monte Carlo valuation
model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic
assessment. Expected volatility represents the extent to which our stock price is expected to fluctuate between now and the
award’s anticipated term. We use the historical volatility of Noble Energy common stock for the three-year period ended prior
to the date of award. The risk-free rate is based on a three-year period for US Treasury securities as of the year ended prior to
the date of award.
The assumptions used in valuing market based restricted stock awards granted were as follows:
Number of Simulations
Expected Volatility
Risk-Free Rate
Restricted stock activity was as follows:
Year Ended December 31,
2017
500,000
35%
1.5%
2016
500,000
38%
1.0%
2015
500,000
30%
0.8%
Subject to Time
Vesting
Subject to Market
Conditions
Number of
Shares
Weighted
Average
Award Date
Fair Value
(per share)
Number of
Shares
Weighted
Average
Award Date
Fair Value
(per share)
$
Outstanding at December 31, 2016
Awarded (1)
Vested (1)
Forfeited
Outstanding at December 31, 2017
(1) During 2017, we awarded approximately 1.9 million shares of restricted stock for the conversion of Clayton Williams Energy shares into
Noble Energy shares as part of the Clayton Williams Energy Acquisition. All awards subsequently vested during 2017. These awards are
included in the above table. See Note 3. Clayton Williams Energy Acquisition.
1,371,780
3,201,504
(2,515,383)
(218,164)
1,839,737
1,502,992
464,608
(219,883)
(535,012)
1,212,705
36.37
36.26
34.93
37.66
37.21
27.43
24.25
44.61
33.12
25.55
$
$
$
The total fair value of restricted stock that vested was $34 million in 2017, $24 million in 2016, and $62 million in 2015.
The weighted average award-date fair value of restricted stock awarded was $35.45 per share in 2017, $29.99 per share in 2016,
and $35.53 per share in 2015.
As of December 31, 2017, $41 million of compensation cost related to all of our unvested restricted stock awarded under the
Plans remained to be recognized. The cost is expected to be recognized over a weighted-average period of 1.4 years. Common
stock dividends accrue on restricted stock awards and are paid upon vesting. We issue new shares of our common stock when
awarding restricted stock.
Cash-Settled Awards On February 1, 2016, we issued cash-settled awards to certain employees under the 1992 Plan in lieu of
a portion of restricted stock and stock options. We issued approximately one million awards (so called phantom units, the
nomenclature used in accounting literature), a portion of which are subject to the Company's achievement of certain levels of
total shareholder return relative to a pre-determined industry peer group. The fair value of the market based phantom unit
awards was estimated on the date of award using a Monte Carlo valuation model and assumed 500,000 simulations, 38%
expected volatility and a risk-free rate of 0.9%.
These phantom units represent a hypothetical interest in the Company, and, once vested, are settled in cash. The phantom unit
value at vesting will equal the lesser of the fair market value of a share of common stock of the Company as of the vesting date
(2-year cliff vesting for officers and 3-year cliff vesting for non-officers) or up to four times the fair market value of a share of
common stock of the Company, which was $31.65, as of the grant date.
As of December 31, 2017, we had accrued a liability of $10 million related to the phantom units. No phantom units were
awarded in 2017.
128
Table of Contents
Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Phantom unit activity was as follows:
Subject to Time
Vesting
Subject to Market Conditions
Number of
Units
Weighted
Average
Award Date
Fair Value
(per share)
Number of
Units
Weighted
Average
Award Date
Fair Value
(per share)
712,089
(13,305)
(88,625)
610,159
$
$
31.65
31.65
31.65
31.65
209,504
$
—
(42,021)
167,483
$
6.82
—
6.82
6.82
Outstanding at December 31, 2016
Vested
Forfeited
Outstanding at December 31, 2017
As of December 31, 2017, $6 million of compensation cost related to phantom units remained to be recognized. The cost is expected
to be recognized over a weighted-average period of 1.1 years. The total fair value of phantom units that vested in 2017 was de
minimis. Common stock dividends accrue on phantom units and will be paid upon vesting.
Other Compensation Plans
401(k) Plan We sponsor a 401(k) savings plan. All regular employees are eligible to participate. We make contributions to
match employee contributions up to the first 6% of compensation deferred into the plan, and certain profit sharing contributions
for employees hired on or after May 1, 2006, based upon their ages and salaries. We made cash contributions of $31 million in
2017, $32 million in 2016, and $35 million in 2015.
Deferred Compensation Plan We have a non-qualified deferred compensation plan for which participant-directed investments
are held in a rabbi trust and are available to satisfy the claims of our creditors in the event of bankruptcy or insolvency.
Participants in that nonqualified deferred compensation plan may elect to receive distributions in either cash or shares of our
common stock. Components of that rabbi trust are as follows:
(millions, except share amounts)
Rabbi Trust Assets
Mutual Fund Investments
Noble Energy Common Stock (at Fair Value)
Total Rabbi Trust Assets
Liability Under Related Deferred Compensation Plan
Number of Shares of Noble Energy Common Stock Held by Rabbi Trust
December 31,
2017
2016
$
$
$
57
14
71
71
470,030
$
$
$
62
26
88
88
671,269
Assets of that rabbi trust, other than our common stock, are invested in certain mutual funds that cover an investment spectrum
ranging from equities to money market instruments. These mutual funds have published market prices and are reported at fair
value. See Note 13. Fair Value Measurements and Disclosures. The mutual funds are included in the mutual fund investments
account in other noncurrent assets in the consolidated balance sheets.
Shares of our common stock held by the rabbi trust holding common stock are accounted for as treasury stock (recorded at cost,
$16.72 per share) in the shareholders’ equity section of the consolidated balance sheets. Amounts payable to plan participants
are included in other noncurrent liabilities in the consolidated balance sheets and include the market value of the shares of our
common stock.
Approximately 400,000 shares, or 85%, of our common stock held in respect of one nonqualified deferred compensation plan at
December 31, 2017 were attributable to a member of our Board of Directors. The shares are being distributed in equal
installments over the next two years. Distributions of 200,000 shares were made in each of 2017, 2016 and 2015. In addition,
plan participants sold 1,238 shares of our common stock in 2017, 1,009 shares in 2016, and 1,009 shares in 2015. Proceeds
were invested in mutual funds and/or distributed to plan participants. Distributions to plan participants were valued at $21
million in 2017, $22 million in 2016 and $18 million in 2015.
All fluctuations in market value of the deferred compensation liability have been reflected in other non-operating (income)
expense, net in the consolidated statements of operations. We recognized deferred compensation expense (income) of $9
million in 2017, $11 million in 2016 and $(12) million in 2015.
129
Table of Contents
Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
We also maintain other nonqualified deferred compensation plans for the benefit of certain of our employees. Deferred
compensation liabilities of $116 million and $121 million were outstanding at December 31, 2017 and 2016, respectively, under
those other plans.
Note 13. Fair Value Measurements and Disclosures
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets. The following
methods and assumptions were used to estimate the fair values:
Cash, Cash Equivalents, Accounts Receivable and Accounts Payable The carrying amounts approximate fair value due to the
short-term nature or maturity of the instruments.
Mutual Fund Investments Our mutual fund investments consist of various publicly-traded mutual funds that include
investments ranging from equities to money market instruments. The fair values are based on quoted market prices for identical
assets.
Commodity Derivative Instruments Our commodity derivative instruments may include variable to fixed price commodity
swaps, two-way collars, three-way collars, swaptions, enhanced swaps and basis swaps. We estimate the fair values of these
instruments using published forward commodity price curves as of the date of the estimate. The discount rate used in the
discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. The fair
values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and
the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk,
each based on the current published credit default swap rates. In addition, for collars, we estimate the option values of the put
options sold and the contract floors and ceilings using an option pricing model which takes into account market volatility,
market prices and contract terms. See Note 8. Derivative Instruments and Hedging Activities.
Deferred Compensation Liability The value is dependent upon the fair values of mutual fund investments and shares of our
common stock held in a rabbi trust. See Mutual Fund Investments above.
Stock-Based Compensation Liability A portion of the value of the liability associated with our phantom unit plan is dependent
upon the fair value of Noble Energy common stock as of the end of each reporting period. See Note 12. Stock-Based and Other
Compensation Plans.
130
Table of Contents
Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Measurement information for assets and liabilities that are measured at fair value on a recurring basis was as follows:
(millions)
December 31, 2017
Financial Assets
Mutual Fund Investments
Commodity Derivative Instruments
Financial Liabilities
Commodity Derivative Instruments
Portion of Deferred Compensation
Liability Measured at Fair Value
Stock Based Compensation Liability
Measured at Fair Value
December 31, 2016
Financial Assets
Mutual Fund Investments
Commodity Derivative Instruments
Financial Liabilities
Commodity Derivative Instruments
Portion of Deferred Compensation
Liability Measured at Fair Value
Stock Based Compensation Liability
Measured at Fair Value
Fair Value Measurements Using
Significant
Other
Observable
Inputs
(Level 2) (1)
Quoted
Prices in
Active
Markets
(Level 1) (1)
Significant
Unobservable
Inputs
(Level 3) (1)
Adjustment (2)
Fair Value
Measurement
$
$
$
$
57
—
—
(71)
(10)
71
—
—
(88)
(9)
— $
7
— $
—
— $
(5)
(78)
—
—
—
—
—
5
—
—
— $
5
— $
—
— $
(5)
(121)
—
—
—
—
—
5
—
—
57
2
(73)
(71)
(10)
71
—
(116)
(88)
(9)
(1) See Note 1. Summary of Significant Accounting Policies – Fair Value Measurements for a description of the fair value hierarchy.
(2) Amount represents the impact of netting clauses within our master agreements that allow us to net cash settle asset and liability positions
with the same counterparty.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Certain assets and liabilities are measured at fair
value on a nonrecurring basis in our consolidated balance sheets. The following methods and assumptions were used to estimate
the fair values:
Asset Impairments In 2017, 2016, and 2015, we determined that the carrying amounts of certain oil and gas assets were not
recoverable from future cash flows and, therefore, were impaired. The assets were reduced to their estimated fair values as
noted below.
Inventory Impairment In 2016, and 2015, we determined that the carrying amount of certain of our materials and supplies
inventory was greater than its net realizable value or not recoverable from future cash flows. These assets were, therefore,
adjusted as noted below.
Marcellus Shale Firm Transportation Liability As of December 31, 2017, we had recorded a $90 million liability representing
the discounted present value of our remaining obligation under firm transportation contracts. See Note 17 – Commitments and
Contingencies.
131
Table of Contents
Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Information about the impaired assets is as follows:
Description
(millions)
Year Ended December 31, 2017
Impaired Oil and Gas Properties $
Year Ended December 31, 2016
Impaired Oil and Gas Properties
Impaired Materials and Supplies
Inventory
Year Ended December 31, 2015
Impaired Oil and Gas Properties
Impaired Materials and Supplies
Inventory
Quoted Prices in
Active Markets
(Level 1) (1)
Fair Value Measurements Using
Significant Other
Observable Inputs
(Level 2) (1)
Significant
Unobservable
Inputs (Level 3) (1)
Net Book
Value (2)
Total Pre-tax
(Non-cash)
Impairment Loss
— $
— $
— $
70
$
—
—
—
—
—
—
—
—
—
91
752
61
92
105
1,285
81
70
92
14
533
20
(1) See Note 1. Summary of Significant Accounting Policies – Fair Value Measurements for a description of the fair value hierarchy.
(2) Amount represents net book value at the date of assessment.
The fair values of properties held and used were determined as of the date of the assessment using discounted cash flow
models. The discounted cash flows were based on management’s expectations for the future. Inputs included estimates of future
crude oil and natural gas production, commodity prices based on commodities sales contract terms or commodity price curves
as of the date of the estimate, estimated operating and development costs, and a risk-adjusted discount rate of 10%. The fair
values of assets held for sale were based on anticipated sales proceeds less costs to sell. Costs associated with abandoned
properties were completely written off. See Note 5. Asset Impairments.
Additional Fair Value Disclosures
Debt The fair value of fixed-rate, public debt is estimated based on the published market prices for the same or similar issues.
As such, we consider the fair value of our public, fixed-rate debt to be a Level 1 measurement on the fair value hierarchy.
At December 31, 2017, our variable-rate, non-public debt included the Revolving Credit Facility and the Noble Midstream
Services Revolving Credit Facility. The fair value is estimated based on significant other observable inputs. As such, we
consider the fair value of these facilities to be a Level 2 measurement on the fair value hierarchy. See Note 10. Long-Term
Debt.
Fair value information regarding our debt is as follows:
(millions)
Long-Term Debt, Net (1)
December 31,
2017
December 31,
2016
Carrying
Amount
Fair Value
Carrying
Amount
Fair Value
$
6,586
$
7,142
$
6,739
$
7,112
(1) Excludes unamortized discount, premium, debt issuance costs and capital lease obligations.
Note 14. Segment Information
During second quarter 2017, as a result of the strategic changes in our US onshore portfolio, we established our Midstream
business as a new reportable segment. The Midstream segment, which includes the consolidated accounts of Noble Midstream
Partners, additional US onshore midstream assets and US onshore equity method investments, was previously reported within
the United States reportable segment. As a result, we now have the following reportable segments: United States (US onshore
and Gulf of Mexico); Eastern Mediterranean (Israel and Cyprus); West Africa (Equatorial Guinea, Cameroon and Gabon);
Other International (Newfoundland (Canada), Suriname, Falkland Islands and new ventures); and Midstream.
The geographical reportable segments are in the business of crude oil and natural gas exploration, development, production, and
acquisition (Oil and Gas Exploration and Production or E&P). The Midstream reportable segment owns, operates, develops and
acquires domestic midstream infrastructure assets with current focus areas being the DJ and Delaware Basins. Expenses related
to debt, headquarters depreciation and corporate general and administrative expenses are recorded at the corporate level. Prior
132
Table of Contents
Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
period amounts are presented on a comparable basis.
(In millions)
Year Ended December 31, 2017
Oil, NGL and Gas Sales from
Third Parties (2)
Income from Equity Method
Investees and Other (3)
Intersegment Revenues
Total Revenues
Lease Operating Expense
Production and Ad Valorem
Taxes
Gathering, Transportation and
Processing Expense
Total Production Expense
DD&A
Clayton Williams Energy
Acquisition Expenses
Loss on Debt Extinguishment
Loss on Marcellus Shale
Upstream Divestiture
Asset Impairments
Gain on Commodity Derivative
Instruments
(Loss) Income Before Income
Taxes
Equity Method Investments
Additions to Long Lived Assets
Goodwill (4)
Total Assets at End of Year (5)
Year Ended December 31, 2016
Oil, NGL and Gas Sales from
Third Parties (2)
Income from Equity Method
Investees and Other
Intersegment Revenues
Total Revenues
Lease Operating Expense
Production and Ad Valorem
Taxes
Gathering, Transportation and
Processing Expense
Total Production Expense
DD&A
Asset Impairments
Loss on Commodity Derivative
Instruments
(Loss) Income Before Income
Taxes
Equity Method Investments
Additions to Long Lived Assets
Total Assets at End of Year (5)
Oil and Gas Exploration and Production
Midstream
Consolidated
United
States
Eastern
Mediter-
ranean
West
Africa
Other
Int'l
United
States
Intersegment
Eliminations
and Other (1) Corporate
$
4,060
$ 3,156
$
534
$
370
$ — $
— $
— $
196
—
4,256
571
—
—
3,156
466
138
135
432
1,141
2,053
100
98
2,379
70
550
1,151
1,739
100
—
2,379
63
(63)
(92)
(2,191)
305
2,851
1,310
21,476
(2,365)
—
1,994
1,310
15,767
—
—
534
29
—
—
29
76
—
—
—
—
—
120
—
490
90
—
—
90
146
—
—
—
—
29
—
—
—
—
—
—
—
4
—
—
—
7
—
76
277
353
—
3
70
73
30
—
—
—
—
—
413
—
411
—
2,846
203
225
34
—
1,308
(54)
—
(34)
—
114
233
80
423
—
1,357
—
(277)
(277)
(14)
—
(188)
(202)
(5)
—
—
—
—
—
(62)
—
(79)
—
(163)
$
3,389
$ 2,416
$
540
$
433
$ — $
— $
— $
102
—
3,491
542
—
—
2,416
418
78
76
480
1,100
2,454
92
564
1,058
2,103
—
139
126
(1,772)
(1,277)
400
—
1,526
1,353
—
—
540
37
—
—
37
81
88
—
543
—
88
50
—
483
105
—
—
105
205
—
13
(338)
217
54
21,011
16,153
2,233
1,479
133
—
—
—
—
—
—
—
6
4
—
(199)
—
(6)
89
52
200
252
—
2
44
46
19
—
—
176
183
58
851
—
(200)
(200)
(18)
—
(128)
(146)
—
—
—
(51)
—
(53)
(98)
—
—
—
—
—
—
—
—
63
—
98
—
—
—
(559)
—
102
—
247
—
—
—
—
—
—
—
—
40
—
(626)
—
32
304
Table of Contents
Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
(In millions)
Consolidated
Oil and Gas Exploration and Production Midstream
United
States
Eastern
Mediter-
ranean
West
Africa
Other
Int'l
United
States
Intersegment
Eliminations
and Other (1) Corporate
Year Ended December 31, 2015
Oil, NGL and Gas Sales from
Third Parties (2)
Income from Equity Method
Investees and Other
Intersegment Revenues
Total Revenues
Lease Operating Expense
Production and Ad Valorem
Taxes
Gathering, Transportation and
Processing Expense
Total Production Expense
DD&A
Asset Impairments
Gain on Commodity Derivative
Instruments
(Loss) Income Before Income
Taxes
Equity Method Investments
Additions to Long Lived Assets
Total Assets at End of Year (5)
$
3,093
$ 2,011
$
497
$
580
$
5
$
— $
— $
90
—
3,183
563
—
—
2,011
398
127
126
306
996
2,131
533
366
890
1,677
158
(501)
(347)
(2,219)
(1,693)
453
—
3,062
2,409
—
—
497
42
—
—
42
70
36
—
313
—
147
39
—
619
131
—
—
131
326
339
(154)
(90)
227
124
24,196
18,043
2,676
2,299
—
—
5
4
—
—
4
—
—
—
(229)
—
177
205
51
119
170
—
1
25
26
14
—
—
123
226
146
799
—
(119)
(119)
(12)
—
(85)
(97)
—
—
—
(21)
—
(21)
(46)
—
—
—
—
—
—
—
—
44
—
—
(622)
—
80
220
(1) Intersegment eliminations related to (loss) income before income taxes are the result of Midstream expenditures. These costs are presented
as property, plant and equipment within the E&P business on an unconsolidated basis, in accordance with the successful efforts method of
accounting, and are eliminated upon consolidation.
(2) Revenues from third parties for all foreign countries, in total, were $904 million in 2017, $973 million in 2016, and $1.1 billion in 2015.
(3) The midstream segment includes revenues of $19 million from third party customers.
(4) Goodwill is associated with the Texas reporting unit. See Note 1. Summary of Significant Accounting Policies.
(5) Long-lived assets located in all foreign countries, in total, were $2.8 billion, $3.0 billion, and $3.9 billion at December 31, 2017, 2016,
and 2015, respectively.
134
Table of Contents
Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 15. Concentration of Risk
Concentration of Market Risk The largest single non-affiliated purchasers of our production were as follows:
Year Ended December 31, 2017
BP (1)
Shell (2)
Year Ended December 31, 2016
Glencore Energy UK Ltd
Shell (2)
Year Ended December 31, 2015
Glencore Energy UK Ltd
Shell (2)
Percentage of
Crude Oil Sales
Percentage of Total
Oil, Gas & NGL Sales
15%
22%
22%
24%
30%
18%
10%
13%
12%
13%
18%
11%
(1) Includes sales to BP North American Funding Company, BP Company Commercial and/or BP Company.
(2) Includes sales to Shell Trading (US) Company and/or Shell International Trading and Shipping Limited.
We believe the loss of any one purchaser would not have a material effect on our financial position or results of operations since
there are numerous potential purchasers of our production.
Concentration of Credit Risk Certain of our financial instruments, including cash equivalents, trade and joint interest
receivables and derivative instruments, may expose us to credit risk.
A significant portion of our cash is located in our foreign subsidiaries. The cash is denominated in US dollars and invested in
highly liquid money market funds and short term deposits with original maturities of three months or less at the time of
purchase. Although our cash and cash equivalents are deposited with major international banks and financial institutions,
concentrations of cash in certain foreign locations may increase credit risk. We monitor the creditworthiness of the banks and
financial institutions with which we invest and review the securities underlying our investment accounts. We believe that losses
from nonperformance are unlikely to occur; however, we are not able to predict sudden changes in creditworthiness.
Our accounts receivable result from sales of crude oil, NGL and natural gas production, and joint interest billings to our
partners for their share of expenses on joint venture projects for which we are the operator. Joint venture projects, especially in
deepwater or remote international locations, can be very capital cost intensive. Thus the receivables from our joint venture
partners can become significant.
Our accounts receivable reflect a broad national and international customer base, which limits our exposure to concentrations of
credit risk. The majority of these receivables have payment terms of 30 days or less. We continually monitor the
creditworthiness of the counterparties, some of which are not as creditworthy as we are and may experience liquidity
problems. We have obtained credit enhancements from some parties, including one of our significant crude oil purchasers, in
the way of parental guarantees or letters of credit. However, we do not have all of our trade credit or joint interest receivables
protected through guarantees or credit support. Nonperformance by a trade creditor or joint venture partner could result in
losses.
Our hedging activity may increase counterparty credit risk, especially during periods of falling commodity prices. We conduct
our hedging activities with a diverse group of investment grade major banks and market participants. We monitor the
creditworthiness of our hedge counterparties, and our internal hedge policies provide for mark-to-market exposure limits. We
use master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting
counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be
“net settled” at the time of election.
135
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Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 16. Additional Shareholders’ Equity Information
Common Stock and Treasury Stock Activity in shares of our common stock and treasury stock was as follows:
Common Stock Shares Issued
Shares, Beginning of Period
Exercise of Common Stock Options
Restricted Stock Awarded, Net of Forfeitures (1)
Shares Exchanged in Clayton Williams Energy Acquisition
Shares, End of Period
Treasury Stock
Shares, Beginning of Period
Shares Received in Payment of Withholding Taxes Due on Vesting of Shares of Restricted
Stock (2)
Rabbi Trust Shares Distributed and/or Sold
Shares, End of Period
Additional Information
Incremental Shares From Assumed Conversion of Dilutive Stock Options, Restricted Stock,
and Shares of Common Stock in Rabbi Trust (2)
Number of Antidilutive Stock Options, Shares of Restricted Stock and Shares of Common
Stock in Rabbi Trust excluded from Dilutive Loss per Share
Year Ended December 31,
2017
2016
471,360,427
382,882
2,912,936
54,087,136
528,743,381
469,718,512
954,898
687,017
—
471,360,427
37,961,316
37,925,625
1,026,891
(201,238)
38,786,969
236,700
(201,009)
37,961,316
—
—
15,619,276
14,218,319
(1) The 2017 amount includes approximately 1.9 million shares of restricted stock awarded to former holders of Clayton Williams Energy
outstanding stock awards as part of the Clayton Williams Energy Acquisition. See Note 3. Clayton Williams Energy Acquisition.
(2) The 2017 amount includes approximately 720,000 shares of common stock from Clayton Williams Energy shareholders for the payment
of withholding taxes due on the vesting of Clayton Williams Energy restricted shares and options pursuant to the purchase and sale
agreement.
(3) For the years ended December 31, 2017 and 2016, all outstanding options and non-vested restricted shares have been excluded from the
calculation of diluted earnings (loss) per share as Noble Energy incurred a loss. Therefore, inclusion of outstanding options and non-
vested restricted shares in the calculation of diluted earnings (loss) per share would be anti-dilutive.
Issuance of Noble Midstream Partners Common Units On December 15, 2017, Noble Midstream Partners closed an offering
of 3,680,000 common units, generating net proceeds of approximately $174 million, net of offering costs. On June 26, 2017,
Noble Midstream Partners engaged in a private placement offering of 3,525,000 common units, generating proceeds of
approximately $138 million, net of offering costs.
In third quarter 2016, Noble Midstream Partners completed its initial public offering of 14,375,000 common units, generating
proceeds of $299 million, net of offering costs.
Subsequent Event - Share Repurchase Program On February 15, 2018, we announced the Company's Board of Directors
authorized a share repurchase program of $750 million which expires December 31, 2020. All purchases will be made in
accordance with applicable securities laws from time to time in open market or private transactions, depending on market
conditions, and may be discontinued at any time.
Accumulated Other Comprehensive Loss (AOCL) AOCL in the shareholders’ equity section of the balance sheet included:
136
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Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
(millions)
December 31, 2014
Realized Amounts Reclassified Into Earnings
Unrealized Change in Fair Value
December 31, 2015
Realized Amounts Reclassified Into Earnings
Unrealized Change in Fair Value
December 31, 2016
Realized Amounts Reclassified Into Earnings
Unrealized Change in Fair Value
December 31, 2017
Accumulated Other Comprehensive Loss
Pension-
Interest Rate
Related and
Cash Flow
Other
Hedges
Total
$
$
(23) $
1
—
(22)
1
—
(21)
1
—
(20) $
(67) $
62
(6)
(11)
4
(3)
(10)
4
(4)
(10) $
(90)
63
(6)
(33)
5
(3)
(31)
5
(4)
(30)
All amounts in the table above are reported net of tax, using an effective income tax rate of 35%.
AOCL at December 31, 2017 included deferred losses of $20 million, net of tax, related to interest rate derivative instruments.
This amount is being reclassified to earnings as an adjustment to interest expense over the term of our senior notes due March
2041.
Note 17. Commitments and Contingencies
Legal Proceedings We are involved in various legal proceedings in the ordinary course of business. These proceedings are
subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters and we believe
that the ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of
operations or cash flows.
Colorado Air Matter In April 2015, we entered into a joint consent decree (Consent Decree) with the US Environmental
Protection Agency, US Department of Justice, and State of Colorado to improve emission control systems at a number of our
condensate storage tanks that are part of our upstream crude oil and natural gas operations within the Non-Attainment Area of
the DJ Basin. The Consent Decree was entered by the US District Court for the District of Colorado on June 2, 2015.
The Consent Decree, which alleges violations of the Colorado Air Pollution Prevention and Control Act and Colorado’s federal
approved State Implementation Plan, specifically Colorado Air Quality Control Commission Regulation Number 7, requires us
to perform certain injunctive relief activities and to complete mitigation projects and supplemental environmental projects
(SEP), and pay a civil penalty. Costs associated with the settlement consist of $4.95 million in civil penalties which were paid
in 2015. Mitigation costs of $4.5 million and SEP costs of $4 million are being expended in accordance with schedules
established in the Consent Decree. Costs associated with the injunctive relief are also being expended in accordance with
schedules established in the Consent Decree. Over the last three years, 2015 through 2017, we spent approximately $72.0
million to undertake injunctive relief at certain tank systems following the outcome of adequacy of design evaluations and
certain operation and maintenance activities to handle potential peak instantaneous vapor flow rates. Future costs associated
with injunctive relief are not yet precisely quantifiable as we are continually evaluating various approaches to meet the ongoing
obligations of the Consent Decree.
Overall compliance with the Consent Decree has resulted in the temporary shut-in and permanent plugging and abandonment of
certain wells and associated tank batteries. Consent Decree compliance could result in additional temporary shut-ins and
permanent plugging and abandonment of certain wells and associated tank batteries. The Consent Decree sets forth a detailed
compliance schedule with deadlines for achievement of milestones through early 2019 that may be extended depending on
certain situations. The Consent Decree contains additional obligations for ongoing inspection and monitoring beyond that
which is required under existing Colorado regulations.
We have concluded that the penalties, injunctive relief, and mitigation expenditures that resulted from this settlement did not
have, and based on currently available information will not have, a material adverse effect on our financial position, results of
operations or cash flows.
Colorado Water Quality Control Division Matter In January 2017, we received a Notice of Violation/Cease and Desist Order
(NOV/CDO) advising us of alleged violations of the Colorado Water Quality Control Act (Act) and its implementing
regulations as it relates to our Colorado Discharge Permit System General Permit for construction activities associated with oil
and gas exploration and/or production within our Wells Ranch Drilling and Production field located in Weld County, Colorado
137
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Index to Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
(Permit). The NOV/CDO further orders us to cease and desist from all violations of the Act, the regulations and the Permit and
to undertake certain corrective actions. Given the uncertainty associated with administrative actions of this nature, we are
unable to predict the ultimate outcome of this action at this time but believe that the resolution of this action will not have a
material adverse effect on our financial position, results of operations or cash flows.
Colorado Oil & Gas Conservation Commission Administrative Order on Consent In November 2017, we received a proposed
Administrative Order on Consent (AOC) from the COGCC to resolve allegations of noncompliance associated with site
preparation and stabilization at an oil and gas location in Weld County, Colorado. The AOC, which provides for an opportunity
to further discuss the offer of settlement, has not yet been executed. Given the uncertainty associated with administrative
actions of this nature, we are unable to predict the ultimate outcome of this action at this time but believe that the resolution of
this action will not have a material adverse effect on our financial position, results of operations or cash flows.
Colorado Air Compliance Order on Consent In April 2017, we received a proposed Compliance Order on Consent (COC)
from the Colorado Department of Public Health and Environment’s Air Pollution Control Division (APCD) to resolve
allegations of noncompliance associated with compliance testing of certain engines subject to various General Permit 02
conditions and/or individual permit conditions. In May 2017, we reached a final resolution with the APCD and executed the
COC, which requires payment of a civil penalty of $24,710 and an expenditure of no less than $98,840 on an approved SEP(s).
This resolution is not believed to have a material adverse effect on our financial position, results of operations or cash flows.
Transportation and Gathering Obligations As part of our Marcellus Shale upstream divestiture, we retained certain
transportation and gathering obligations to flow Marcellus Shale natural gas production to various markets inside and outside of
the Marcellus Basin. Our financial commitment for these agreements, which have remaining terms of two to 16 years, is
approximately $1.4 billion, undiscounted. The agreements for firm transportation primarily relate to services on certain
pipelines which were recently placed into service in late 2017/early 2018 or for services on new pipeline projects to be
constructed by, and connecting to, existing and new interstate pipeline systems with estimated in-service dates in late 2018. The
associated commitments are included in the table below. See Note 1. Summary of Significant Accounting Policies – Exit Costs.
We also have transportation and gathering obligations to flow DJ Basin, Eagle Ford Shale, and Gulf of Mexico production to
various markets. Our financial commitment for these agreements, which have remaining terms of one to 11 years, is
approximately $781 million, undiscounted. The commitment is included in the table below.
Non-Cancelable Leases and Other Commitments We hold leases and other commitments for drilling rigs, buildings, equipment
and other property. Rental expense for office buildings and oil and gas operations equipment was $69 million in 2017, $76
million in 2016, and $84 million in 2015.
Minimum commitments as of December 31, 2017 consist of the following:
(millions)
2018
2019
2020
2021
2022
2023 and Thereafter
Total
Drilling,
Equipment,
and Purchase
Obligations
636
$
167
40
13
8
32
896
$
Transportation
and Gathering
Obligations
$
$
215
252
247
223
182
1,355
2,474
Operating
Lease
Obligations
44
$
33
32
32
33
156
330
$
Capital
Lease and
Other
Obligations(1)
74
$
45
42
29
21
124
335
$
$
$
Total
969
497
361
297
244
1,667
4,035
(1) Annual lease payments, net to our interest, exclude regular maintenance and operational costs. See Note 10. Long-Term Debt.
138
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Index to Financial Statements
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
In accordance with US GAAP for disclosures about oil and gas producing activities, and SEC rules for oil and gas reporting
disclosures, we are making the following disclosures about our crude oil, NGL and natural gas reserves and exploration and
production activities. In 2017 we established our Midstream business as a new reportable segment. The results of operations,
costs incurred and capitalized costs associated with our Midstream reportable segment are not included in this disclosure. Prior
period amounts are presented on a comparable basis.
Reserves There are numerous uncertainties inherent in estimating quantities of proved crude oil, NGL and natural gas reserves
and reserves engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that
cannot be precisely measured. The accuracy of any reserves estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the
estimate may justify revision of such estimate. Accordingly, reserves estimates are often different from the quantities of crude
oil, NGL and natural gas that are ultimately recovered.
Economic producibility of reserves is dependent on the crude oil, NGL and natural gas prices used in the reserves estimate. We
based our December 31, 2017, 2016, and 2015 reserves estimates on 12-month average commodity prices, unless contractual
arrangements designate the price to be used, in accordance with SEC rules. However, commodity prices are volatile and
declines in crude oil, NGL and natural gas prices could result in negative reserves revisions. Production, development and
abandonment costs are based on year-end economic conditions; therefore increases in these costs could also result in negative
reserves revisions.
Reserves Estimates Estimates of our proved reserves and associated future net cash flows are made solely by our engineers
and are the responsibility of management. For additional information regarding our reserves estimation process and internal
controls see Items 1. and 2. Business and Properties – Proved Reserves Disclosures – Internal Controls Over Reserves
Estimates and Technologies Used in Reserves Estimation.
Third-Party Reserves Audit We retained Netherland, Sewell & Associates, Inc. (NSAI), independent, third-party petroleum
engineers, to perform a reserves audit of proved reserves as of December 31, 2017. See Items 1. and 2. Business and Properties
– Proved Reserves Disclosures.
Definitions The following definitions apply to the terms used in the paragraphs above:
Reserves Estimate The determination of an estimate of a quantity of oil or gas reserves that are thought to exist at a certain
date, considering existing prices and reservoir conditions.
Reserves Audit The process of reviewing certain of the pertinent facts interpreted and assumptions underlying a reserves
estimate prepared by another party and the rendering of an opinion about the appropriateness of the methodologies employed,
the adequacy and quality of the data relied upon, the depth and thoroughness of the reserves estimation process, the
classification of reserves appropriate to the relevant definitions used, and the reasonableness of the estimated reserves
quantities.
The following definitions apply to our categories of proved reserves:
Proved Oil and Gas Reserves Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience
and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward,
from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the
time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain,
regardless of whether deterministic or probabilistic methods are used for the estimation. The project to produce the
hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a
reasonable time.
Developed Oil and Gas Reserves Proved developed oil and gas reserves are reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods or in which the cost of the required equipment is
relatively minor compared with the cost of a new well.
Undeveloped Oil and Gas Reserves PUDs are reserves that are expected to be recovered from new wells on undrilled acreage,
or from existing wells where a relatively major expenditure is required for recompletion. Undrilled locations can be classified
as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled
within five years, unless the specific circumstances justify a longer time.
For complete definitions of proved reserves, refer to SEC Regulation S-X, Rule 4-10(a)(6), (22) and (31).
139
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Index to Financial Statements
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Proved Oil Reserves (Unaudited) The following reserves schedule was developed by our qualified petroleum engineers and
sets forth the changes in estimated quantities of proved crude oil reserves:
Crude Oil and Condensate (MMBbls)
United
States
Equatorial
Guinea
Israel
Total
Proved Reserves as of:
December 31, 2014
Revisions of Previous Estimates (1)
Extensions, Discoveries and Other Additions (2)
Purchase of Minerals in Place (3)
Sale of Minerals in Place
Production (5)
December 31, 2015
Revisions of Previous Estimates (1)
Extensions, Discoveries and Other Additions (2)
Sale of Minerals in Place
Production (5)
December 31, 2016
Revisions of Previous Estimates (1)
Extensions, Discoveries and Other Additions (2)
Purchase of Minerals in Place (3)
Sale of Minerals in Place (4)
Production (5)
December 31, 2017
Proved Developed Reserves as of:
December 31, 2014
December 31, 2015
December 31, 2016
December 31, 2017
Proved Undeveloped Reserves as of:
December 31, 2014
December 31, 2015
December 31, 2016
December 31, 2017
236
(56)
42
65
(2)
(29)
256
14
66
(4)
(36)
296
29
104
43
(12)
(41)
419
119
137
138
176
117
119
158
243
65
(5)
—
—
—
(12)
48
(4)
—
—
(10)
34
2
—
—
—
(7)
29
52
34
34
29
13
14
—
—
3
—
—
—
—
—
3
—
—
—
—
3
—
6
—
—
—
9
3
3
3
3
—
—
—
6
304
(61)
42
65
(2)
(41)
307
10
66
(4)
(46)
333
31
110
43
(12)
(48)
457
174
174
175
208
130
133
158
249
(1) The 2015 US revisions were primarily associated with negative price revisions of 70 MMBbls to our onshore programs due to a decline
in the 12-month average price of crude oil; partially offset by positive revisions of 14 MMBbls due to producing well performance and
optimized lateral lengths in the Delaware Basin and Eagle Ford Shale. Equatorial Guinea revisions were associated with negative price
revisions.
The 2016 US revisions associated with positive performance and/or decreases in development or operating costs included revisions of 33
MMBbls in the DJ Basin, Marcellus Shale, Delaware Basin and Gulf of Mexico; partially offset by negative revisions of 19 MMBbls due
to lower commodity prices. Equatorial Guinea revisions were primarily due to lower commodity prices.
The 2017 US revisions associated with positive performance totaled 17 MMBbls, of which 14 were primarily attributable to the
Delaware Basin due to continued optimization of well development and improved producing well performance. Revisions also included
positive price revisions of 12 MMBbls.
(2) The 2015 increase in US reserves was attributable to DJ Basin development.
The 2016 increase in US reserves included 38 MMBbls in the DJ Basin and 28 MMBbls in the Delaware Basin and Eagle Ford Shale,
and was associated with increased performance from our horizontal drilling programs.
The 2017 increase in US reserves included additions of 59 MMBbls in the Delaware Basin, 42 MMBbls in the DJ Basin and 3 MMBbls
in the Eagle Ford Shale primarily due to the addition of planned new locations and activity.
(3) The 2015 increase was attributable to reserves acquired in the Rosetta Merger.
140
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Index to Financial Statements
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
The 2017 increase was attributable to the reserves acquired in the Clayton Williams Energy Acquisition.
(4)
In 2017, we sold the Marcellus Shale upstream assets and other non-strategic US onshore assets.
(5) Equatorial Guinea production included sales from Alba Plant of approximately 1 MMBbl in 2017 and 3 MMBbl in each of the years
2016 and 2015.
See Items 1. and 2. Business and Properties – Proved Reserves Disclosures, Note 3. Clayton Williams Energy Acquisition and Note 4.
Acquisitions, Divestitures and Merger.
141
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Index to Financial Statements
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Proved NGL Reserves (Unaudited) The following reserves schedule was developed by our qualified petroleum engineers and
sets forth the changes in estimated quantities of proved NGL reserves:
NGLs (MMBbls)
Equatorial
Guinea
United
States
Total
Proved Reserves as of:
December 31, 2014
Revisions of Previous Estimates (1)
Extensions, Discoveries and Other Additions (2)
Purchase of Minerals in Place (3)
Sale of Minerals in Place
Production (4)
December 31, 2015
Revisions of Previous Estimates (1)
Extensions, Discoveries and Other Additions (2)
Purchase of Minerals in Place
Sale of Minerals in Place
Production (4)
December 31, 2016
Revisions of Previous Estimates (1)
Extensions, Discoveries and Other Additions (2)
Purchase of Minerals in Place (3)
Sale of Minerals in Place (5)
Production (4)
December 31, 2017
Proved Developed Reserves as of:
December 31, 2014
December 31, 2015
December 31, 2016
December 31, 2017
Proved Undeveloped Reserves as of:
December 31, 2014
December 31, 2015
December 31, 2016
December 31, 2017
113
(37)
15
100
(1)
(14)
176
16
31
4
—
(20)
207
31
32
7
(38)
(21)
218
64
101
113
119
49
75
94
99
15
—
—
—
—
(2)
13
1
—
—
—
(2)
12
1
—
—
—
(2)
11
8
5
12
11
7
8
—
—
128
(37)
15
100
(1)
(16)
189
17
31
4
—
(22)
219
32
32
7
(38)
(23)
229
72
106
125
130
56
83
94
99
(1) The 2015 US revisions were primarily associated with negative price revisions of 44 MMBbls related to our onshore programs due to a
decline in the 12-month average price; partially offset by a positive revision from our Marcellus Shale program due to positive well
performance.
The 2016 US revisions were primarily associated with positive performance revisions of 11 MMBbls in the Marcellus Shale and 9
MMBbls in the DJ Basin; partially offset by negative commodity price revisions of 4 MMBbls.
The 2017 US revisions associated with positive performance revisions totaled 25 MMBbls, including 11 MMBbls in the Delaware Basin,
8 MMBbls in the Eagle Ford Shale and 6 MMBbls in the DJ Basin, due to continued optimization of well development and improved
producing well performance. Revisions also included positive price revisions of 6 MMBbls.
(2) The 2015 additions included 14 MMBbls due to positive producing well performance and optimized lateral lengths in the DJ Basin.
The 2016 additions in US reserves primarily included an increase of 15 MMBbls in the DJ Basin and 14 MMBbls in the Delaware Basin
and Eagle Ford shale due to improved well performance and/or decreases in development or operating costs.
The 2017 additions in US reserves included 19 MMBbls in the DJ Basin, 9 MMBbls in the Delaware Basin and 4 MMBbls in the Eagle
Ford Shale primarily due to the addition of planned new locations and activity.
(3) The 2015 increase was attributable to reserves acquired in the Rosetta Merger.
The 2017 increase was attributable to the reserves acquired in the Clayton Williams Energy Acquisition.
142
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Index to Financial Statements
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
(4) Equatorial Guinea production represented sales from the Alba Plant.
(5) In 2017, we sold the Marcellus Shale upstream assets and other non-strategic US onshore assets.
See Items 1. and 2. Business and Properties – Proved Reserves Disclosures, Note 3. Clayton Williams Energy Acquisition and Note 4.
Acquisitions, Divestitures and Merger.
143
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Index to Financial Statements
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Proved Gas Reserves (Unaudited) The following reserves schedule was developed by our qualified petroleum engineers and
sets forth the changes in estimated quantities of proved natural gas reserves:
Natural Gas and Casinghead Gas (Bcf)
United
States
Israel (1)
Equatorial
Guinea
Total
Proved Reserves as of:
December 31, 2014
Revisions of Previous Estimates (2)
Extensions, Discoveries and Other Additions (3)
Purchase of Minerals in Place (4)
Sale of Minerals in Place
Production
December 31, 2015
Revisions of Previous Estimates (2)
Extensions, Discoveries and Other Additions (3)
Purchase of Minerals in Place
Sale of Minerals in Place (5)
Production
December 31, 2016
Revisions of Previous Estimates (2)
Extensions, Discoveries and Other Additions (3)
Purchase of Minerals in Place (4)
Sale of Minerals in Place (5)
Production
December 31, 2017
Proved Developed Reserves as of:
December 31, 2014
December 31, 2015
December 31, 2016
December 31, 2017
Proved Undeveloped Reserves as of:
December 31, 2014
December 31, 2015
December 31, 2016
December 31, 2017
2,804
(705)
257
629
(16)
(258)
2,711
181
492
—
(224)
(322)
2,838
124
299
46
(1,264)
(222)
1,821
1,459
1,813
1,817
983
1,345
898
1,021
838
2,416
(20)
—
—
—
(92)
2,304
(3)
—
—
(214)
(103)
1,984
292
3,271
—
—
(99)
5,448
1,973
1,879
1,600
1,793
443
425
384
3,655
613
4
—
—
—
(83)
534
38
—
—
—
(86)
486
13
—
—
(1)
(87)
411
377
247
486
411
236
287
—
—
5,833
(721)
257
629
(16)
(433)
5,549
216
492
—
(438)
(511)
5,308
429
3,570
46
(1,265)
(408)
7,680
3,809
3,939
3,903
3,187
2,024
1,610
1,405
4,493
(1)
In accordance with the terms of the Framework, we are required to reduce our ownership in the Tamar and Dalit fields from 36% to 25%
by year-end 2021. During 2016, we reduced our ownership to 32.5% through the sale of a 3.5% interest. At December 31, 2017, an
additional 7.5% interest is included in assets held for sale. Proved reserves associated with the interest currently held for sale total
approximately 502 Bcf, including 89 Bcf of PUDs, at December 31, 2017 and are included in the table above. In January 2018, we
entered into an agreement to divest the 7.5% interest. See Note 4. Acquisitions, Divestitures and Merger.
(2) The 2015 US revisions were primarily associated with negative price revisions of 1.1 Tcf to our onshore programs due to a decline in the
12-month average price, offset by a positive revision primarily to our Marcellus Shale program due to positive well performance.
Equatorial Guinea revisions were associated with positive performance revisions to the Alba field. Israel revisions were primarily
associated with negative performance revisions in the Mari-B field.
The 2016 US revisions were primarily associated with positive performance and/or decreases in development or operating costs and
included 167 Bcf in the Marcellus Shale and 95 Bcf in the DJ Basin, partially offset by negative commodity price revisions of 81 Bcf.
Equatorial Guinea revisions were associated with positive performance revisions of 58 Bcf at the Alba field, partially offset by negative
commodity price revisions of 20 Bcf.
The 2017 US revisions were associated primarily with positive well performance and an increase in commodity prices. Net performance
revisions of 66 Bcf primarily included 81 Bcf in the Eagle Ford Shale and 31 Bcf in the Delaware Basin, partially offset by negative
performance revisions of 49 Bcf in the DJ Basin primarily associated vertical well locations. The 2017 Israel performance revisions of
144
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Index to Financial Statements
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
292 Bcf were associated with the integration of the Tamar 8 well results into our geologic modeling across the reservoir. Positive price
revisions were approximately 71 Bcf.
(3) The 2015 increase in US reserves included an increase of 176 Bcf in the DJ Basin and 81 Bcf from Marcellus Shale development due to
positive producing well performance and optimized lateral lengths.
The 2016 increase in US reserves included positive performance revisions associated with our horizontal drilling programs including 230
Bcf in the Marcellus Shale, 185 Bcf in the DJ Basin, and 77 Bcf in the Delaware Basin and Eagle Ford Shale.
The 2017 increase in US reserves included additions of 224 Bcf in the DJ Basin, 53 Bcf in the Delaware Basin and 22 Bcf in the Eagle
Ford Shale primarily due to the addition of planned new locations and activity. The 2017 increase in Israel reserves represented sanction
of the first phase of development of the Leviathan natural gas project.
(4) The 2015 increase was attributable to reserves acquired in the Rosetta Merger.
The 2017 increase was attributable to the reserves acquired in the Clayton Williams Energy Acquisition.
(5)
In 2016, we sold US onshore assets in the DJ Basin and Eagle Ford Shale. We also executed an acreage exchange in the Marcellus Shale
where we relinquished 185 Bcf, and we reduced our ownership in the Tamar field, offshore Israel.
In 2017, we sold the Marcellus Shale upstream assets and other non-strategic US onshore assets.
See Items 1. and 2. Business and Properties – Proved Reserves Disclosures, Note 3. Clayton Williams Energy Acquisition and Note 4.
Acquisitions, Divestitures and Merger.
145
Table of Contents
Index to Financial Statements
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Results of Operations for Oil and Gas Producing Activities (Unaudited) Results of operations for crude oil and natural gas
producing activities within the E&P reporting segments are as follows:
United
States
Israel
Equatorial
Guinea
Other
Int'l
Total
(millions)
Year Ended December 31, 2017
Revenues
Production Costs (1)
Exploration Expense
DD&A
Loss on Marcellus Shale Upstream Divestiture (2)
Asset Impairments (3)
(Loss) Income before Income Taxes
Income Tax Expense (Benefit) (4)
Results of Operations (5)
Year Ended December 31, 2016
Revenues
Production Costs (1)
Exploration Expense (6)
DD&A
Asset Impairments (4)
(Loss) Income before Income Taxes
Income Tax Expense (Benefit) (4)
Results of Operations (5)
Year Ended December 31, 2015
Revenues
Production Costs (1)
Exploration Expense
DD&A
Asset Impairments (3)
Income (Loss) before Income Taxes
Income Tax Expense (4)
Results of Operations (5)
$
$
$
$
$
$
$
3,156
1,199
102
1,739
2,379
63
(2,326)
(814)
(1,512) $
$
2,416
1,108
245
2,103
—
(1,040)
(364)
(676) $
$
2,011
916
202
1,677
158
(942)
(330)
(612) $
534
49
—
76
—
—
409
98
311
540
49
26
81
88
296
74
222
497
60
6
70
36
325
86
239
$
$
$
$
$
$
370
103
1
146
—
—
120
30
90
$
$
$
433
118
469
205
—
(359)
(90)
(269) $
$
580
145
1
326
339
(231)
(58)
(173) $
— $
2
85
4
—
7
(98)
—
(98) $
— $
1
185
6
4
(196)
—
(196) $
$
5
6
279
—
—
(280)
(5)
(275) $
4,060
1,353
188
1,965
2,379
70
(1,895)
(686)
(1,209)
3,389
1,276
925
2,395
92
(1,299)
(380)
(919)
3,093
1,127
488
2,073
533
(1,128)
(307)
(821)
(1) Production costs consist of lease operating expense, production and ad valorem taxes, transportation and gathering expense, and general
and administrative expense supporting oil and gas operations.
(2) See Note 4. Acquisitions, Divestitures and Merger.
(3)
2017 asset impairments relate primarily to the Gulf of Mexico Troubadour well.
2016 asset impairments relate to certain Leviathan development concept costs.
2015 asset impairments related to reductions in the forward crude oil prices as of December 31, 2015 and revisions in expected field
abandonment and other costs for offshore properties.
See Note 5. Asset Impairments.
(4)
Income tax expense is based upon respective corporate statutory tax rates. During 2017, 2016, and 2015, we incurred exploration
expense in currently non-commercial other international locations; therefore, no tax benefit was included in income tax expense
associated with other international as we could not conclude it was more likely than not that some portion or all of the deferred tax assets
would be realized.
(5) Results of operations exclude the mark-to-market gain or loss on commodity derivative instruments, corporate overhead and interest
costs. See Note 8. Derivative Instruments and Hedging Activities.
(6) Equatorial Guinea exploration expense includes amounts related to the write off of costs associated with certain discoveries. See Note 6.
Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
146
Table of Contents
Index to Financial Statements
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities (Unaudited)
Costs incurred include both capitalized costs and costs charged to expense when incurred for oil and gas property acquisition,
exploration, and development activities associated with the E&P reporting segments. Costs incurred also include new AROs
established in the current year, as well as changes to AROs resulting from changes to cost estimates during the year. Exploration
costs presented below include the costs of drilling and equipping successful and unsuccessful exploration wells during the year,
geological and geophysical expenses, and the costs of retaining undeveloped leaseholds. Development costs include the costs of
drilling and equipping development wells. Costs associated with activities of our Midstream business and other corporate
activities are not included.
United
States
Israel
Equatorial
Guinea
Other
Int'l (1)
Total
(millions)
December 31, 2017
Property Acquisition Costs
Proved (2)
Unproved (2)
Exploration Costs (3)
Development Costs (4)
Total Consolidated Operations
December 31, 2016
Property Acquisition Costs
Proved (2)
Unproved (2)
Exploration Costs (4)
Development Costs (4)
Total Consolidated Operations
December 31, 2015
Property Acquisition Costs
Proved (2)
Unproved (2)
Exploration Costs (3)
Development Costs (4)
Total Consolidated Operations
$
$
$
$
$
$
839
1,817
59
1,870
4,585
$
$
— $
—
6
483
489
$
— $
234
264
905
1,403
$
— $
—
26
109
135
$
1,613
1,478
206
2,111
5,408
$
$
— $
—
22
104
126
$
— $
—
4
33
37
$
— $
—
25
31
56
$
— $
—
22
75
97
$
— $
—
90
(39)
51
$
— $
—
44
—
44
$
— $
2
234
10
246
$
839
1,817
159
2,347
5,162
—
234
359
1,045
1,638
1,613
1,480
484
2,300
5,877
(1) Other International includes Newfoundland, Suriname, Falkland Islands, other new ventures and previous North Sea operations, which
are in the process of being decommissioned.
(2)
(3)
2017 proved and unproved property acquisition costs include amounts allocated from the Clayton Williams Energy Acquisition (See
Note 3. Clayton Williams Energy Acquisition) and the Delaware Basin Acquisition (See Note 4. Acquisitions, Divestitures and Merger).
2016 unproved property acquisition costs relate to the termination of the Marcellus Shale joint development agreement. See Note 4.
Acquisitions, Divestitures and Merger.
2015 proved and unproved property acquisition costs include amounts allocated from the Rosetta Merger. See Note 4. Acquisitions,
Divestitures and Merger.
2017 exploration costs include primarily capitalized interest on Gulf of Mexico projects, and $7 million dry hole cost related to the
Araku-1 exploration well, offshore Suriname. The remainder relates to seismic expense and drilling costs.
2016 exploration costs include drilling and completion of $44 million in the Gulf of Mexico.
2015 exploration costs include drilling and completion of $22 million in the Gulf of Mexico.
(4) Worldwide development costs include amounts spent to develop PUDs of approximately $1.2 billion in 2017, $656 million in 2016, and
$1.5 billion in 2015.
Israel development costs include $416 million related to initial development of the Leviathan field and $63 million related to the Tamar 8
development well in 2017. Amounts incurred in 2016 and 2015 related primarily to development of the Tamar discovery.
Equatorial Guinea development costs primarily relate to the Alba field unitization project in 2017 and drilling and well completion and
installation and construction of a compression platform in the Alba field in 2016 and 2015.
147
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Index to Financial Statements
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
US development costs include a decrease of $17 million in asset retirement obligations due to downward revisions and increases of $20
million in 2016 and $194 million in 2015.
Israel development costs include increases in asset retirement obligations of $4 million in 2017 and $46 million in 2015.
Equatorial Guinea development costs include increases (decreases) in asset retirement obligations of $14 million in 2017 and $(10)
million in 2015.
Other International development costs include increases (decreases) in asset retirement obligations of $(40) million in 2017 mainly
associated with the North Sea abandonment project and $2 million in 2015.
Capitalized Costs Relating to Oil and Gas Producing Activities (Unaudited) Aggregate capitalized costs relating to crude
oil and natural gas producing activities within the E&P reporting segments are as follows:
(millions)
Unproved Oil and Gas Properties (1)
Proved Oil and Gas Properties (2)
Total Oil and Gas Properties
Accumulated DD&A
Net Capitalized Costs
December 31,
2017
2016
$
2,978
$
26,111
29,089
(12,538)
16,551
$
$
2,197
27,530
29,727
(12,265)
17,462
(1) Unproved oil and gas property cost at December 31, 2017 include previous acquisition costs of $1.6 billion related to the Clayton
Williams Energy Acquisition, and $1.1 billion and $149 million related to the Delaware Basin and Eagle Ford Shale properties.
Unproved oil and gas property cost at December 31, 2016 include previous acquisition costs of $1.2 billion related to the Eagle Ford
Shale and Delaware Basin properties and $758 million related to Marcellus Shale properties.
(2) Proved oil and gas properties at December 31, 2017 include asset retirement costs of $941 million and assets held for sale of $448
million.
Proved oil and gas properties at December 31, 2016 include asset retirement costs of $884 million and $18 million of assets held for sale.
148
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Index to Financial Statements
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited) The
following information is based on our best estimate of the required data for the Standardized Measure of Discounted Future Net
Cash Flows in accordance with US GAAP. The standards require the use of a 10% discount rate. This information is not the fair
value nor does it represent the expected present value of future cash flows of our proved oil and gas reserves.
United
States
Israel (1)
Equatorial
Guinea
Other
Int'l (2)
Total
(millions)
December 31, 2017
Future Cash Inflows (3)
Future Production Costs (4)
Future Development Costs (5)
Future Income Tax Expense (6)
Future Net Cash Flows
10% Annual Discount for Estimated Timing of Cash Flows
Standardized Measure of Discounted Future Net Cash Flows
December 31, 2016
Future Cash Inflows (3)
Future Production Costs (4)
Future Development Costs (5)
Future Income Tax Expense
Future Net Cash Flows
10% Annual Discount for Estimated Timing of Cash Flows
Standardized Measure of Discounted Future Net Cash Flows
December 31, 2015
Future Cash Inflows (3)
Future Production Costs (4)
Future Development Costs (5)
Future Income Tax Expense
Future Net Cash Flows
10% Annual Discount for Estimated Timing of Cash Flows
Standardized Measure of Discounted Future Net Cash Flows
$ 30,061
(11,020)
(5,941)
(948)
12,152
(5,202)
6,950
$
$ 19,924
(8,756)
(4,813)
(941)
5,414
(2,308)
3,106
$
$ 19,099
(8,728)
(4,092)
(837)
5,442
(2,100)
3,342
$
$
$
$
$
$
$
29,998
(2,517)
(1,706)
(13,088)
12,687
(8,993)
3,694
10,159
(764)
(725)
(4,228)
4,442
(2,329)
2,113
11,835
(1,128)
(682)
(5,281)
4,744
(2,452)
2,292
$
$
$
$
$
$
2,028
(932)
(109)
(216)
771
(113)
658
$ — $ 62,087
— (14,469)
(51)
(7,807)
— (14,252)
(51)
25,559
(14,301)
7
(44) $ 11,258
$
1,851
(1,001)
(83)
(141)
626
(84)
542
2,965
(1,351)
(101)
(189)
1,324
(262)
1,062
$ — $ 31,934
— (10,521)
(5,721)
(5,310)
10,382
(4,696)
5,686
(100)
—
(100)
25
(75) $
$
$ — $ 33,899
— (11,207)
(4,975)
(6,307)
11,410
(4,782)
6,628
(100)
—
(100)
32
(68) $
$
(1)
In accordance with the Framework, we are required to reduce our ownership in the Tamar and Dalit fields from 36% to 25% by year-end
2021. During 2016, we reduced our ownership to 32.5% through the sale of a 3.5% interest. Therefore, amounts at December 31, 2017
and 2016 reflect a 32.5% working interest, while 2015 amounts reflect a 36% working interest. At December 31, 2017, 7.5% of our
32.5% interest is included in assets held for sale. The portion of the standardized measure of discounted future net cash flows included in
the table above, and associated with the interest currently held for sale, totals approximately $650 million at December 31, 2017. See
Note 4. Acquisitions, Divestitures and Merger. The 2017 increase in the standardized measure of discounted future net cash inflows
relates primarily to the sanction of the first phase of development of the Leviathan field.
(2) Other International represents North Sea abandonment costs.
(3) The standardized measure of discounted future net cash flows does not include cash flows relating to anticipated future methanol sales.
(4) Production costs include lease operating expense, production and ad valorem taxes, transportation expense and general and
administrative expense supporting crude oil and natural gas operations.
(5) Future development costs include future abandonment costs for each location. See Note 9. Asset Retirement Obligations.
(6) Future income tax expense includes the effect of statutory tax rates and the impact of tax deductions, tax credits and allowances relating
to our proved reserves. As of December 31, 2017, US future income tax expense includes the expected impact of the recent Tax Reform
Legislation. As of December 31, 2017, 2016 and 2015, future income tax expense for Israel also includes the effect of estimated future
profit levy taxes and changes to corporate income tax rates.
149
Table of Contents
Index to Financial Statements
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Prices and Other Assumptions in Discounted Future Net Cash Flows (Unaudited) Future cash inflows are computed by
applying a 12-month average commodity price, adjusted for location and quality differentials on a field-by-field basis, to year-
end quantities of proved reserves, except in those instances where fixed and determinable price changes are provided by
contractual arrangements at year-end. The discounted future cash flow estimates do not include the effects of derivative
instruments. Average prices per region are as follows:
December 31, 2017
Average Crude Oil and Condensate Price per Bbl
Average Natural Gas Price per Mcf
Average NGL Price per Bbl
December 31, 2016
Average Crude Oil and Condensate Price per Bbl
Average Natural Gas Price per Mcf
Average NGL Price per Bbl
December 31, 2015
Average Crude Oil and Condensate Price per Bbl
Average Natural Gas Price per Mcf
Average NGL Price per Bbl
United
States
Israel
Equatorial
Guinea
Total
$
$
$
$
$
$
47.81
2.83
22.32
37.36
2.07
14.30
42.03
2.16
14.15
$
$
$
46.82
5.43
—
36.05
5.07
—
48.23
5.08
—
$
$
$
53.12
0.27
37.23
42.45
0.27
26.12
51.03
0.27
29.92
48.13
4.54
23.02
37.87
3.02
14.94
43.50
3.18
15.23
The discounted future net cash flows are computed using a 12-month average commodity price applied to our year-end
quantities of proved reserves, unless contractual arrangements designate the price to be used. We performed a sensitivity of our
discounted future net cash flows to reflect a price reduction to our 12-month average commodity price. We estimate that a 10%
per Bbl reduction in the average price of crude oil and NGLs from the 12-month average price for 2017 would reduce the
discounted future net cash flows before income taxes by approximately $1.2 billion and $0.3 billion, respectively. We estimate
that a 10% per Mcf reduction in the average price of natural gas from the 12-month average price for 2017 would reduce the
discounted future net cash flows before income taxes by approximately $1 billion.
Future production and development costs, which include dismantlement and restoration expense, are computed by estimating
the expenditures to be incurred in developing and producing the proved crude oil, natural gas and NGL reserves at the end of
the year, based on year-end costs, and assuming continuation of existing economic conditions.
Future development costs include amounts that we expect to spend to develop PUDs of approximately $1.7 billion in 2018,
$1.9 billion in 2019 and $1.4 billion in 2020.
Future income tax expense is computed by applying the appropriate year-end statutory tax rates to the estimated future pre-tax
net cash flows relating to proved crude oil, natural gas and NGL reserves, less the tax bases of the properties involved. Future
income tax expense gives effect to tax credits and allowances, but does not reflect the impact of general and administrative
costs and exploration expenses of ongoing operations.
150
Table of Contents
Index to Financial Statements
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Sources of Changes in Discounted Future Net Cash Flows (Unaudited) Principal changes in the aggregate standardized
measure of discounted future net cash flows attributable to proved crude oil, natural gas and NGL reserves are as follows:
Year Ended December 31,
2016
2017
2015
(millions)
Standardized Measure of Discounted Future Net Cash Flows, Beginning of Year
Changes in Standardized Measure of Discounted Future Net Cash Flows
Sales of Oil and Gas Produced, Net of Production Costs
Net Changes in Prices and Production Costs (1)
Extensions, Discoveries and Improved Recovery, Less Related Costs
Changes in Estimated Future Development Costs
Development Costs Incurred During the Period
Revisions of Previous Quantity Estimates
Purchases of Minerals in Place (2)
Sales of Minerals in Place
Accretion of Discount
Net Change in Income Taxes (3)
Change in Timing of Estimated Future Production and Other (4)
Aggregate Change in Standardized Measure of Discounted Future Net Cash Flows
Standardized Measure of Discounted Future Net Cash Flows, End of Year
$
5,686
$
6,628
$ 13,979
(2,674)
2,436
3,711
(537)
1,975
1,462
423
(643)
778
(1,669)
310
$
5,572
$ 11,258
(2,230)
(593)
463
(373)
1,090
364
161
(951)
919
414
(206)
(942)
5,686
(2,026)
(12,603)
442
1,135
2,639
(1,051)
2,747
(46)
1,789
2,075
(2,452)
(7,351)
6,628
$
$
$
$
(1) The increase in 2017 and the decrease in 2015 were driven primarily by higher and lower, respectively, 12-month average commodity prices.
(2) Purchase of minerals in 2017 relates to reserves acquired in the Clayton Williams Energy Acquisition.
Purchase of minerals in 2015 relates to reserves acquired in the Rosetta Merger.
(3) The increase in 2017 future income tax expense relates primarily to the increase in profit and levy taxes in Israel, partially offset by the
decrease in future corporate income tax rate in Israel. The increase in profits tax is driven by a significant increase in future cash flows
related to the Leviathan project sanctioning in 2017. The increase in US tax expense due to the increase in future taxable income was offset
by the decrease in tax expense associated with utilization of future net operating losses and decrease in applicable tax rate from 35% to 21%
due to the changes in the US Tax Law effective January 1, 2018. For 2015, future income tax expense for Israel includes the effect of
estimated future profit levy taxes which partially offset the increase in future net cash flows.
(4) The decrease in 2015 reflects revisions in our estimated timing of production and development activity.
151
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Index to Financial Statements
Noble Energy, Inc.
Supplemental Quarterly Financial Information
(Unaudited)
Supplemental quarterly financial information is as follows:
March 31,
Quarter Ended
Sep 30,
June 30,
Dec 31,
Total
(millions except per share amounts)
2017 (1) (3)
Revenues
Income (Loss) Before Income Taxes
Net Income (Loss)
Less: Net Income Attributable to Noncontrolling Interests
Net Income (Loss) Attributable to Noble Energy
Net Income (Loss) Per Share, Basic
Net Income (Loss) Per Share, Diluted
2016 (2) (3)
Revenues
Loss Before Income Taxes
Net Income (Loss)
Less: Net Income Attributable to Noncontrolling Interests
Net Loss Attributable to Noble Energy
Net Loss Per Share, Basic and Diluted
(1) First quarter 2017 included the following:
• No unusual or infrequent activity.
Second quarter 2017 included the following:
•
$
$
1,036
59
47
11
36
0.08
0.08
$
724
(453)
(287)
—
(287)
(0.67)
$ 1,059
(2,334)
(1,498)
14
(1,512)
(3.20)
(3.20)
847
(498)
(315)
—
(315)
(0.73)
$
$
960
(208)
(115)
21
(136)
$ 1,201
292
516
22
494
$ 4,256
(2,191)
(1,050)
68
(1,118)
(0.28)
(0.28)
910
(280)
(143)
1
(144)
(0.33)
1.01
1.01
(2.38)
(2.38)
$ 1,010
(541)
(240)
12
(252)
(0.59)
$ 3,491
(1,772)
(985)
13
(998)
(2.32)
$2.4 billion loss on Marcellus Shale upstream divestiture (See Note 4. Acquisitions, Divestitures and Merger).
Third quarter 2017 included the following:
•
$98 million loss on extinguishment of debt (See Note 10. Long-Term Debt).
Fourth quarter 2017 included the following:
•
•
$270 million deferred tax benefit, net, related to recent changes in federal income tax regulations; and
$334 million gain on sale of mineral and royalty assets (See Note 4. Acquisitions, Divestitures and Merger).
(2) First quarter 2016 included the following:
•
$80 million gain on extinguishment of debt.
Second quarter 2016 included the following:
•
$25 million purchase price allocation adjustment related to Rosetta Merger (See Note 4. Acquisitions, Divestitures and Merger).
Third quarter 2016 included the following:
•
$81 million undeveloped leasehold impairment expense (See Note 6. Capitalized Exploratory Well Costs and Undeveloped
Leasehold Costs).
Fourth quarter 2016 included the following:
•
•
$579 million dry hole costs included in exploration expense (See Note 6. Capitalized Exploratory Well Costs and Undeveloped
Leasehold Costs); and
$92 million property impairment charges (See Note 5. Asset Impairments)
(3) The sum of the individual quarterly earnings (loss) may not agree with year-to-date earnings (loss) as each quarterly computation is
based on the earnings (loss) for the individual quarter as reported with rounding applied.
152
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Index to Financial Statements
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in
the reports we file or furnish to the SEC under the Securities Exchange Act of 1934, as amended, is recorded, processed,
summarized and reported within the time periods specified by the SEC’s rules and forms, and that information is accumulated
and communicated to management, including our principal executive officer and principal financial officer, as appropriate, to
allow timely decisions regarding required disclosure.
Our principal executive officer and principal financial officer have evaluated the effectiveness of our “disclosure controls and
procedures,” as such term is defined in Rule 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended, as
of the end of the period covered by this Annual Report on Form 10-K. Based upon their evaluation, they have concluded that
our disclosure controls and procedures were effective and provide an effective means to ensure that information required to be
disclosed in the reports that we file or furnish under the Securities Exchange Act of 1934, as amended, is recorded, processed,
summarized and reported within the time periods specified by the SEC's rules and forms and that information is accumulated
and communicated to management, including our principal executive officer and principal financial officer, as appropriate, to
allow timely decisions regarding required disclosure.
In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures,
no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the
control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the
likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and
procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that our
controls will succeed in achieving their goals under all future conditions.
Management’s Annual Report on Internal Control over Financial Reporting
The management report called for by Item 308(a) of Regulation S-K is incorporated herein by reference to Management’s
Report on Internal Control over Financial Reporting, included in Item 8. Financial Statements and Supplementary Data.
The independent auditor’s attestation report called for by Item 308(b) of Regulation S-K is incorporated herein by reference to
Report of Independent Registered Public Accounting Firm (Internal Control Over Financial Reporting), included in Item
8. Financial Statements and Supplementary Data.
Changes in Internal Control over Financial Reporting
Our management is also responsible for establishing and maintaining adequate internal controls over financial reporting, as
defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Our internal controls were
designed to provide reasonable assurance as to the reliability of our financial reporting and the preparation and presentation of
the consolidated financial statements for external purposes in accordance with US GAAP.
Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements.
Projections of any evaluation of the effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Our management has assessed the effectiveness of our internal controls over financial reporting as of December 31, 2017.
Based on our assessment, our internal controls over financial reporting were effective. There were no changes in internal
controls over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are
reasonably likely to materially affect, our internal controls over financial reporting.
Item 9B. Other Information
None.
153
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Item 10. Directors, Executive Officers and Corporate Governance
PART III
The information required by this item is incorporated herein by reference to the 2018 Proxy Statement, which will be filed with
the SEC not later than 120 days subsequent to December 31, 2017.
Item 11. Executive Compensation
The information required by this item is incorporated herein by reference to the 2018 Proxy Statement, which will be filed with
the SEC not later than 120 days subsequent to December 31, 2017.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required by this item is incorporated herein by reference to the 2018 Proxy Statement, which will be filed with
the SEC not later than 120 days subsequent to December 31, 2017.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this item is incorporated herein by reference to the 2018 Proxy Statement, which will be filed with
the SEC not later than 120 days subsequent to December 31, 2017.
Item 14. Principal Accounting Fees and Services
The information required by this item is incorporated herein by reference to the 2018 Proxy Statement, which will be filed with
the SEC not later than 120 days subsequent to December 31, 2017.
Item 15. Exhibits, Financial Statement Schedules
(a) The following documents are filed as a part of this report:
PART IV
(1) Financial Statements: The consolidated financial statements and related notes, together with the reports of KPMG
LLP, Independent Registered Public Accounting Firm, appear in Part II, Item 8, Financial Statements and
Supplementary Data, of this Form 10-K.
(2) Financial Statement Schedules: All schedules for which provision is made in the applicable accounting regulations of
the SEC are not required under the related instruction or are inapplicable and, therefore, have been omitted.
(3) Exhibits: The exhibits listed below on the Index to Exhibits are filed or incorporated by reference as part of this Form
10-K.
154
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Index to Financial Statements
Exhibit Number
INDEX TO EXHIBITS
Exhibit **
2.1
2.2
2.3
— Agreement and Plan of Merger, dated as of January 13, 2017, by and among Noble Energy, Inc., Wild West
Merger Sub Inc., NBL Permian LLC, and Clayton Williams Energy, Inc. (filed as Exhibit 2.1 to the
Registrant’s Current Report on Form 8-K (Date of Report: January 13, 2017) filed January 17, 2017 and
incorporated herein by reference).
— Agreement and Plan of Merger, dated as of May 10, 2015, by and among Noble Energy, Inc., Bluebonnet
Merger Sub Inc. and Rosetta Resources Inc. (filed as Exhibit 2.1 to the Registrant’s Current Report on
Form 8-K (Date of Report: May 10, 2015) filed May 11, 2015 and incorporated herein by reference).
— Exchange Agreement, executed October 29, 2016, by and between CNX Gas Company LLC and Noble
Energy, Inc. (filed as Exhibit 2.3 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended
September 30, 2016 and incorporated herein by reference).
2.4
— Purchase and Sale Agreement among Noble Energy, Inc. and HG Energy II Appalachia, LLC dated May 1,
2017 (filed as Exhibit 2.1 to the Registrant’s Current Report on Form 8-K (Date of Report: May 1, 2017)
filed May 5, 2017 and incorporated herein by reference).
2.5
2.6
3.1
— Purchase Agreement by and among Wheeling Creek Midstream, LLC, Noble Energy US Holdings, LLC
and Noble Energy, Inc. dated May 17, 2017 (filed as Exhibit 2.1 to the Registrant’s Current Report on
Form 8-K (Date of Report: May 17, 2017) filed May 23, 2017 and incorporated herein by reference).
— Letter Agreement by and among Wheeling Creek Midstream LLC, Noble Energy US Holdings, LLC and
Noble Energy, Inc. dated December 7, 2017, filed herewith.
— Restated Certificate of Incorporation of Noble Energy, Inc. (filed as Exhibit 3.3 to the Registrant’s Current
Report on Form 8-K (Date of Report: July 26, 2016) filed July 28, 2016 and incorporated herein by
reference).
3.2
— By-Laws of Noble Energy, Inc. (as amended through January 30, 2018) (filed as Exhibit 3.1 to the
Registrant’s Current Report on Form 8-K (Date of Report: January 30, 2018) filed on February 1, 2018 and
incorporated herein by reference).
3.3
— Certificate of Elimination of the Series A Junior Participating Preferred Stock of Noble Energy, Inc. (filed
as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K (Date of Report: July 26, 2016) filed July
28, 2016 and incorporated herein by reference).
3.4
— Certificate of Elimination of the Series B Mandatorily Convertible Preferred Stock of Noble Energy, Inc.
(filed as Exhibit 3.2 to the Registrant’s Current Report on Form 8-K (Date of Report: July 26, 2016) filed
July 28, 2016 and incorporated herein by reference).
4.1
— Indenture dated as of February 27, 2009 between Noble Energy, Inc. and Wells Fargo Bank, National
Association, as Trustee, relating to senior debt securities of Noble Energy, Inc. (filed as Exhibit 4.1 to the
Registrant’s Current Report on Form 8-K (Date of Report: February 24, 2009) filed February 27, 2009
(File No. 001-07964) and incorporated herein by reference).
4.2
— Second Supplemental Indenture dated as of February 18, 2011, to Indenture dated as of February 27, 2009
between Noble Energy, Inc. and Wells Fargo Bank, National Association, as Trustee, relating to the
Registrant’s 6.000% Notes due 2041 (including the form of 2041 Notes) (filed as Exhibit 4.1 to the
Registrant’s Current Report on Form 8-K (Date of Report: February 15, 2011) filed February 22, 2011 (File
No. 001-07964) and incorporated herein by reference).
4.3
—
4.4
—
Third Supplemental Indenture dated as of December 8, 2011, to Indenture dated as of February 27, 2009
between Noble Energy, Inc. and Wells Fargo Bank, National Association, as Trustee, relating to the
Registrant’s 4.15% Notes due 2021 (including the form of 2021 Notes) (filed as Exhibit 4.2 to the
Registrant’s Current Report on Form 8-K (Date of Report: December 5, 2011) filed December 8, 2011 (File
No. 001-07964) and incorporated herein by reference).
Fourth Supplemental Indenture dated as of November 8, 2013, to Indenture dated as of February 27, 2009
between Noble Energy, Inc. and Wells Fargo Bank, National Association, as Trustee, relating to the
Registrant's 5.25% Notes due 2043 (including the form of 2043 Notes) (filed as Exhibit 4.1 to the
Registrant’s Current Report on Form 8-K (Date of Report: November 5, 2013) filed November 8, 2013
(File No. 001-07964) and incorporated herein by reference).
4.5
— Fifth Supplemental Indenture dated as of November 7, 2014, to Indenture dated as of February 27, 2009
between Noble Energy, Inc. and Wells Fargo Bank, National Association, as Trustee, relating the
Registrant’s 3.900% Notes due 2024 and 5.050% Notes due 2044 (including the forms of 2024 Notes and
2044 Notes) (filed as Exhibit 4.1 to the Registrant’s Current Report on Form 8-K (Date of Report:
November 4, 2014) filed November 7, 2014 (File No. 001-07964) and incorporated herein by reference).
155
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Index to Financial Statements
4.6
— Sixth Supplemental Indenture dated as of July 29, 2015, to Indenture dated as of February 27, 2009
between Noble Energy, Inc. and Wells Fargo Bank, National Association, as Trustee, relating the
Registrant’s 5.625% Notes due 2021, 5.875% Senior Notes due 2022 and 5.875% Notes due 2024
(including the forms of 2021 Notes, 2022 Notes and 2024 Notes) (filed as Exhibit 4.2 to the Registrant’s
Current Report on Form 8-K (Date of Report: July 29, 2015) filed July 31, 2015 and incorporated herein by
reference).
4.7
— Seventh Supplemental Indenture dated as of August 15, 2017, to Indenture dated as of February 27, 2009
between Noble Energy, Inc. and Wells Fargo Bank, National Association, as Trustee, relating to senior debt
securities of Noble Energy, Inc. (filed as Exhibit 4.1 to the Registrant’s Current Report on Form 8-K (Date
of Report: August 15, 2017) filed August 15, 2017 and incorporated herein by reference).
4.8
— Indenture dated as of October 14, 1993 between the Registrant and US Trust Company of Texas, N.A., as
Trustee, relating to the Registrant’s 7¼% Notes Due 2023 (including the form of 2023 Notes) (filed in
paper with the SEC as Exhibit 4.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended
September 30, 1993 on November 12, 1993 and incorporated herein by reference).
4.9
— Indenture dated as of April 1, 1997 between the Registrant and US Trust Company of Texas, N.A., as
Trustee, relating to senior debt securities of Noble Energy, Inc. (filed with the SEC as Exhibit 4.1 to the
Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1997 on May 9, 1997 (File
No. 001-07964) and incorporated herein by reference).
4.10
— First Indenture Supplement dated as of April 2, 1997, to Indenture dated as of April 1, 1997, between the
Registrant and US Trust Company of Texas, N.A., as Trustee, relating to the Registrant’s 8% Senior Notes
Due 2027 (including the form of 2027 Notes) (filed with the SEC as Exhibit 4.2 to the Registrant’s
Quarterly Report on Form 10-Q for the quarter ended March 31, 1997 on May 9, 1997 (File No.
001-07964) and incorporated herein by reference).
4.11
— Second Indenture Supplement, dated as of August 1, 1997, to Indenture dated as of April 1, 1997, between
the Registrant and US Trust Company of Texas, N.A. as trustee, relating to the Registrant’s 7¼% Senior
Debentures Due 2097 (including the form of 2097 Notes) (filed with the SEC as Exhibit 4.1 to the
Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1997 on August 13, 1997 (File
No. 001-07964) and incorporated herein by reference).
10.1
— Credit Agreement, dated October 14, 2011, among Noble Energy, Inc., JPMorgan Chase Bank, N.A., as
administrative agent, Citibank N.A., as syndication agent, Bank of America, N.A., Mizuho Corporate
Bank, LTD., and Morgan Stanley MUFG Loan Partners, LLC, as documentation agents, and certain other
commercial lending institutions named therein (filed as Exhibit 10.1 to the Registrant’s Current Report on
Form 8-K (Date of Report: October 14, 2011) filed October 18, 2011 (File No. 001-07964) and
incorporated herein by reference).
10.2
10.3
10.4
— Commitment Increase Agreement (Existing Lenders) dated September 28, 2012, among Noble Energy,
Inc., JPMorgan Chase Bank, N.A., as administrative agent, and certain other commercial lending
institutions party thereto (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of
Report: September 28, 2012), filed October 2, 2012 (File No. 001-07964) and incorporated herein by
reference).
— Commitment Increase Agreement (New Lenders) dated September 28, 2012, among Noble Energy, Inc.,
JPMorgan Chase Bank, N.A., as administrative agent, and certain other commercial lending institutions
party thereto (filed as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K (Date of Report:
September 28, 2012), filed October 2, 2012 (File No. 001-07964) and incorporated herein by reference).
— First Amendment to Credit Agreement, dated October 3, 2013, by and among Noble Energy, Inc., NBL
International Finance B.V., JPMorgan Chase Bank, N.A., as administrative agent, Citibank N.A., as
syndication agent, and Bank of America, N.A., Bank of Tokyo-Mitsubishi UFJ, Ltd., Mizuho Bank, Ltd.
and DNB Bank ASA, New York Branch as documentation agents, and the other commercial lending
institutions party thereto (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of
Report: October 3, 2013) filed October 9, 2013 (File No. 001-07964) and incorporated herein by
reference).
10.5
— Second Amendment to Credit Agreement, dated August 27, 2015, by and among Noble Energy, Inc.,
JPMorgan Chase Bank, N.A., as administrative agent, Citibank N.A., as syndication agent, and Bank of
America, N.A., Bank of Tokyo-Mitsubishi UFJ, Ltd., Mizuho Bank, Ltd. and DNB Bank ASA, New York
Branch as documentation agents, and the other commercial lending institutions party thereto (filed as
Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Report: August 27, 2015) filed
August 31, 2015 and incorporated herein by reference).
10.6
— Term Loan Agreement as of January 6, 2016 among Noble Energy, Inc., Citibank, N.A., as administrative
agent, Mizuho Bank, Ltd., as syndication agent and certain financial institutions as are or may become
parties thereto (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Report:
January 6, 2016) filed January 7, 2016 and incorporated herein by reference).
10.7*
— Noble Energy, Inc. Retirement Restoration Plan dated effective as of January 1, 2009 (filed as Exhibit 10.1
to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2008 (File No.
001-07964) and incorporated herein by reference).
156
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10.8*
10.9*
— Amendment No. 1 to the Noble Energy, Inc. Retirement Restoration Plan, dated effective as of December
31, 2013 (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Report: December
20, 2013) filed December 23, 2013 (File No. 001-07964) and incorporated herein by reference).
— Noble Energy, Inc. Restoration Trust effective August 1, 2002 (filed as Exhibit 10.3 to the Registrant’s
Annual Report on Form 10-K for the year ended December 31, 2002 (File No. 001-07964) and
incorporated herein by reference).
10.10* — Form of Indemnity Agreement entered into between the Registrant and each of the Registrant’s directors
and bylaw officers (filed in paper with the SEC as Exhibit 10.18 to the Registrant’s Annual Report on
Form 10-K405 for the year ended December 31, 1995 on March 25, 1996 (File No. 001-07964) and
incorporated herein by reference).
10.11* — Noble Energy, Inc. 2005 Non-Employee Director Fee Deferral Plan, dated December 11, 2008, and
effective as of January 1, 2009 (filed as Exhibit 10.20 to the Registrant’s Annual Report on Form 10-K for
the year ended December 31, 2008 (File No. 001-07964) and incorporated herein by reference).
10.12* — 2015 Stock Plan for Non-Employee Directors of Noble Energy, Inc. (as amended and restated effective
October 20, 2015) (filed as Exhibit 10.4 to the Registrant’s Quarterly Report on Form 10-Q for the quarter
ended September 30, 2015 and incorporated herein by reference).
10.13* — Form of Stock Option Agreement under the Noble Energy, Inc. 2015 Non-Employee Director Stock Plan
(filed as Exhibit 10.7 to the Registrant’s Current Report on Form 8-K (Date of Report: January 25, 2016)
filed January 29, 2016 and incorporated herein by reference).
10.14* — Form of Restricted Stock Agreement under the Noble Energy, Inc. 2015 Non-Employee Director Stock
Plan (filed as Exhibit 10.6 to the Registrant’s Current Report on Form 8-K (Date of Report: January 25,
2016) filed January 29, 2016 and incorporated herein by reference).
10.15* — 2005 Stock Plan for Non-Employee Directors of Noble Energy, Inc. (as amended and restated effective
October 20, 2015) (filed as Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q for the quarter
ended September 30, 2015 and incorporated herein by reference).
10.16* — Form of Stock Option Agreement under the Noble Energy, Inc. 2005 Non-Employee Director Stock Plan
(filed as Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30,
2005 (File No. 001-07964) and incorporated herein by reference).
10.17* — Form of Restricted Stock Agreement under the Noble Energy, Inc. 2005 Non-Employee Director Stock
Plan (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Report: January 27,
2009) filed February 2, 2009 (File No. 001-07964) and incorporated herein by reference).
10.18* — Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan (as amended and restated effective
October 20, 2015) (filed as Exhibit 10.2 to Registrant’s Quarterly report on Form 10-Q for the quarter
ended September 30, 2015 (File No. 001-07964) and incorporated herein by reference).
10.19* — Form of Nonqualified Stock Option Agreement under the Noble Energy, Inc. 1992 Stock Option and
Restricted Stock Plan (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of
Report: February 1, 2005) filed February 7, 2005 (File No. 001-07964) and incorporated herein by
reference).
10.20* — Form of Non-Qualified Stock Option Agreement under the Noble Energy, Inc. 1992 Stock Option and
Restricted Stock Plan (filed as Exhibit 10.24 to the Registrant’s Annual Report on Form 10-K for the year
ended December 31, 2012 (File No. 001-07964) and incorporated herein by reference).
10.21* — Form of Restricted Stock Agreement (two-year vested) under the Noble Energy, Inc. 1992 Stock Option
and Restricted Stock Plan (filed as Exhibit 10.25 to the Registrant’s Annual Report on Form 10-K for the
year ended December 31, 2012 (File No. 001-07964) and incorporated herein by reference).
10.22* — Form of Restricted Stock Agreement (three-year vested awards) under the Noble Energy, Inc. 1992 Stock
Option and Restricted Stock Plan (filed as Exhibit 10.26 to the Registrant’s Annual Report on Form 10-K
for the year ended December 31, 2012 (File No. 001-07964) and incorporated herein by reference).
10.23* — Form of Restricted Stock Agreement (performance-vested) under the Noble Energy, Inc. 1992 Stock
Option and Restricted Stock Plan (filed as Exhibit 10.27 to the Registrant’s Annual Report on Form 10-K
for the year ended December 31, 2012 (File No. 001-07964) and incorporated herein by reference).
10.24* — Form of Non-Qualified Stock Option Agreement under the Noble Energy, Inc. 1992 Stock Option and
Restricted Stock Plan (effective February 1, 2016) (filed as Exhibit 10.5 to the Registrant’s Current Report
on Form 8-K (Date of Report: January 25, 2016) filed January 29, 2016 (File No. 001-07964) and
incorporated herein by reference).
10.25* — Form of Restricted Stock Agreement (two-year time vested for non-PEO executive officers) under the
Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan (effective February 1, 2016) (filed as
Exhibit 10.2 to the Registrant’s Current Report on Form 8-K (Date of Report: January 25, 2016) filed
January 29, 2016 and incorporated herein by reference).
10.26* — Form of Restricted Stock Agreement (two-year time vested) under the Noble Energy, Inc. 1992 Stock
Option and Restricted Stock Plan (effective February 1, 2016) (filed as Exhibit 10.26 to the Registrant’s
Annual Report on Form 10-K for the year ended December 31, 2016 and incorporated herein by reference).
157
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Index to Financial Statements
10.27* — Form of Performance Award Agreement (3-year performance vested stock and cash) under the Noble
Energy, Inc. 1992 Stock Option and Restricted Stock Plan (effective February 1, 2016) (filed as Exhibit
10.1 to the Registrant’s Current Report on Form 8-K (Date of Report: January 25, 2016) filed January 29,
2016 and incorporated herein by reference).
10.28* — Form of Cash Award Agreement (two-year vested) under the Noble Energy, Inc. 1992 Stock Option and
Restricted Stock Plan (effective February 1, 2016) (filed as Exhibit 10.4 to the Registrant’s Current Report
on Form 8-K (Date of Report: January 25, 2016) filed January 29, 2016 and incorporated herein by
reference).
10.29* — Form of Restricted Stock Agreement (three-year performance-vested) under the Noble Energy, Inc. 1992
Stock Option and Restricted Stock Plan (effective February 1, 2016) (filed as Exhibit 10.8 to the
Registrant's Current Report on Form 8-K/A (Date of Report: January 25, 2016) filed February 4, 2016 and
incorporated herein by reference).
10.30* — Noble Energy, Inc. 2017 Long-Term Incentive Plan (incorporated by reference to Appendix C to the
Company’s Definitive Proxy Statement on Schedule 14A filed on March 2, 2017).
10.31* — Form of Restricted Stock Award (two-year vested) under the Noble Energy, Inc. 2017 Long-Term Incentive
Plan (filed as Exhibit 10.5 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March
31, 2017 and incorporated herein by reference).
10.32* — Form of Restricted Stock Award (three-year vested) under the Noble Energy, Inc. 2017 Long-Term
Incentive Plan (filed as Exhibit 10.6 to the Registrant’s Quarterly Report on Form 10-Q for the quarter
ended March 31, 2017 and incorporated herein by reference).
10.33* — Form of Stock Option Award under the Noble Energy, Inc. 2017 Long-Term Incentive Plan (filed as
Exhibit 10.7 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017 and
incorporated herein by reference).
10.34* — Form of Performance Share Award under the Noble Energy, Inc. 2017 Long-Term Incentive Plan (filed as
Exhibit 10.8 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017 and
incorporated herein by reference).
10.35* — Form of Restricted Stock Award (3-year time-vested officers) under the Noble Energy, Inc. 2017 Long-
Term Incentive Plan (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Report:
January 29, 2018) filed February 1, 2018 and incorporated herein by reference).
10.36* — Form of Restricted Stock Award (3-year cliff vested) under the Noble Energy, Inc. 2017 Long-Term
Incentive Plan (filed as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K (Date of Report:
January 29, 2018) filed February 1, 2018 and incorporated herein by reference).
10.37* — Amendment to the Noble Energy, Inc. Change of Control Agreement dated effective February 1, 2011
(filed as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K (Date of Report: February 1, 2011),
filed February 4, 2011 (File No. 001-07964) and incorporated herein by reference).
10.38* — Form of Noble Energy, Inc. Change of Control Agreement (as amended effective January 1, 2008), (filed as
Exhibit 10.41 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2007 (File
No. 001-07964) and incorporated herein by reference).
10.39* — Noble Energy, Inc. Change of Control Severance Plan for Executives, as amended and restated (effective
January 30, 2018) filed herewith.
10.40* — Termination of Change of Control Agreement dated effective October 21, 2014 by and between Noble
Energy, Inc. and David L. Stover (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K
(Date of Report: October 21, 2014) filed October 27, 2014 (File No. 001-07964) and incorporated herein
by reference).
10.41* — Noble Energy, Inc. Deferred Compensation Plan (formerly known as the Noble Affiliates, Inc. Deferred
Compensation Plan) as restated effective August 1, 2001 (filed as Exhibit 10.4 to the Registrant’s Annual
Report on Form 10-K for the year ended December 31, 2002 (File No. 001-07964) and incorporated herein
by reference).
10.42* — Amendment No. 1 to the Noble Energy, Inc. Deferred Compensation Plan (formerly known as the Noble
Affiliates, Inc. Deferred Compensation Plan), dated effective as of January 1, 2014 (filed as Exhibit 10.2 to
the Registrant’s Current Report on Form 8-K (Date of Report: December 20, 2013) filed December 23,
2013 (File No. 001-07964) and incorporated herein by reference).
10.43* — Noble Energy, Inc. 2005 Deferred Compensation Plan (as amended effective January 1, 2009) (filed as
Exhibit 10.31 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2008 (File
No. 001-07964) and incorporated herein by reference).
10.44* — Amendment No. 1 to the Noble Energy, Inc. 2005 Deferred Compensation Plan, dated effective as of
January 1, 2014 (filed as Exhibit 10.3 to the Registrant’s Current Report on Form 8-K (Date of Report:
December 20, 2013) filed December 23, 2013 (File No. 001-07964) and incorporated herein by reference).
10.45* — Amendment No. 2 to the Noble Energy, Inc. 2005 Deferred Compensation Plan, dated effective as of
January 1, 2015 (filed as Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter
ended June 30, 2016 (File No. 001-07964) and incorporated herein by reference).
158
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10.46* — Amendment No. 3 to the Noble Energy, Inc. 2005 Deferred Compensation Plan, dated effective as of
August 1, 2016 (filed as Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q for the quarter
ended June 30, 2016 (File No. 001-07964) and incorporated herein by reference).
10.47
— Gas Sale and Purchase Agreement dated March 14, 2012, by and between Noble Energy Mediterranean
Ltd. Isramco Negev 2 Limited Partnership, Delek Drilling Limited Partnership, Avner Oil Exploration
Limited Partnership, and Dor Gas Exploration Limited Partnership (Sellers) and The Israel Electric
Corporation Limited (Purchaser) (filed as Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q/
A for the quarter ended March 31, 2012 (File No. 001-07964) and incorporated herein by reference).
10.48
— Amendment No. 1 dated July 22, 2012 to the Gas Sale and Purchase Agreement dated March 14, 2012, by
and between Noble Energy Mediterranean Ltd. Isramco Negev 2 Limited Partnership, Delek Drilling
Limited Partnership, Avner Oil Exploration Limited Partnership, and Dor Gas Exploration Limited
Partnership (Sellers) and The Israel Electric Corporation Limited (Purchaser) (filed as Exhibit 10.1 to the
Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012 (File No.
001-07964) and incorporated herein by reference).
10.49* — Retention and Confidentiality Agreement between Noble Energy, Inc. and Charles D. Davidson, Chairman
and Chief Executive Officer, effective as of August 14, 2014 (filed as Exhibit 10.1 to the Registrant’s
Current Report on Form 8-K (Date of Report: August 14, 2014) filed August 19, 2014 (File No.
001-07964) and incorporated herein by reference).
10.50
— Support Agreement, dated as of January 13, 2017, by and among certain stockholders affiliated with Ares
Management, LLC, Noble Energy, Inc., and solely for certain purposes specified therein, Clayton Williams
Energy, Inc. (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Report: January
13, 2017) filed January 17, 2017 and incorporated herein by reference).
10.51
— Agreement Not to Dissent, dated as of January 13, 2017, by and among Clayton W. Williams, Jr., Noble
Energy, Inc., and solely for certain purposes specified therein, Clayton Williams Energy, Inc. (filed as
Exhibit 10.2 to the Registrant’s Current Report on Form 8-K (Date of Report: January 13, 2017) filed
January 17, 2017 and incorporated herein by reference).
10.52
— Agreement Not to Dissent, dated as of January 13, 2017, by and among The Williams Children’s
Partnership, Ltd., Noble Energy, Inc., and solely for certain purposes specified therein, Clayton Williams
Energy, Inc. (filed as Exhibit 10.3 to the Registrant’s Current Report on Form 8-K (Date of Report: January
13, 2017) filed January 17, 2017 and incorporated herein by reference).
10.53† — Noble Energy Mediterranean Ltd. Facility Agreement, dated February 24, 2017 by and between NEML
Leviathan Finance Company LTD as Borrower and BNP Paribas, Credit Agricole Corporate and
Investment Bank, ING Bank N.V. Natixis and Societe Generale London Branch as Mandated Lead
Arrangers (filed as Exhibit 10.9 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended
March 31, 2017 and incorporated herein by reference).
12.1
21
23.1
23.2
— Calculation of ratio of earnings to fixed charges, filed herewith.
— Subsidiaries, filed herewith.
— Consent of Independent Registered Public Accounting Firm—KPMG LLP, filed herewith.
— Consent of Independent Petroleum Engineers and Geologists—Netherland, Sewell & Associates, Inc., filed
herewith.
31.1
— Certification of the Registrant's Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002 (18 USC. Section 7241), filed herewith.
31.2
— Certification of the Registrant's Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002 (18 USC. Section 7241), filed herewith.
32.1
— Certification of the Registrant’s Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002 (18 USC. Section 1350), filed herewith.
32.2
— Certification of the Registrant’s Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002 (18 USC. Section 1350), filed herewith.
99.1
— Report of Netherland, Sewell & Associates, Inc., filed herewith.
101.INS — XBRL Instance Document
101.SCH — XBRL Schema Document
101.CAL — XBRL Calculation Linkbase Document
101.LAB — XBRL Label Linkbase Document
101.PRE — XBRL Presentation Linkbase Document
101.DEF — XBRL Definition Linkbase Document
*
Management contract or compensatory plan or arrangement required to be filed as an exhibit hereto.
159
Table of Contents
Index to Financial Statements
**
†
Copies of exhibits will be furnished upon prepayment of 25 cents per page. Requests should be addressed to the
Executive Vice President and Chief Financial Officer, Noble Energy, Inc., 1001 Noble Energy Way, Houston, Texas
77070.
Confidential treatment granted under Rule 24b-2 as to certain portions of this exhibit, which are omitted and filed
separately with the Commission.
Item 16. Form 10-K Summary
See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Executive Summary.
160
Table of Contents
Index to Financial Statements
In this report, the following abbreviations are used:
GLOSSARY
Bbl
BBoe
Bcf
Bcf/d
BCM
BOE
Boe/d
Btu
FPSO
GHG
GSPA
HH
IDP
LNG
LPG
MBbl/d
MBoe/d
Mcf
MMBbls
MMBoe
MMBtu
MMBtu/d
MMcf/d
MMcfe/d
MMgal
NGLs
NYMEX
OPEC
PSC
Tcf
US GAAP
WTI
Barrel
Billion barrels oil equivalent
Billion cubic feet
Billion cubic feet per day
Billion cubic meters
Barrels oil equivalent. Natural gas is converted on the basis of six Mcf of gas per one barrel of crude oil
equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given
commodity price disparities, the price for a barrel of crude oil equivalent for natural gas is significantly
less than the price for a barrel of crude oil. The price for a barrel of NGL is also less than the price for a
barrel of crude oil.
Barrels oil equivalent per day
British thermal unit
Floating production, storage and offloading vessel
Greenhouse gas emissions
Gas Sales Purchase Agreement
Henry Hub index
Integrated Development Plan
Liquefied natural gas
Liquefied petroleum gas
Thousand barrels per day
Thousand barrels oil equivalent per day
Thousand cubic feet
Million barrels
Million barrels oil equivalent
Million British thermal units
Million British thermal units per day
Million cubic feet per day
Million cubic feet equivalent per day
Million gallons
Natural gas liquids
The New York Mercantile Exchange
The Organization of Petroleum Exporting Countries
Production sharing contract
Trillion cubic feet
United States generally accepted accounting principles
West Texas Intermediate index
161
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Index to Financial Statements
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly authorized.
SIGNATURES
Date: February 20, 2018
Date: February 20, 2018
Date: February 20, 2018
NOBLE ENERGY, INC.
(Registrant)
By: /s/ David L. Stover
David L. Stover,
Chairman of the Board, President and Chief Executive Officer
By: /s/ Kenneth M. Fisher
Kenneth M. Fisher,
Executive Vice President, Chief Financial Officer
By: /s/ Dustin A. Hatley
Dustin A. Hatley,
Vice President, Chief Accounting Officer and Controller
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following
persons on behalf of the Registrant and in the capacities and on the dates indicated.
Signature
Capacity in which signed
Date
/s/ David L. Stover
David L. Stover
/s/ Kenneth M. Fisher
Kenneth M. Fisher
/s/ Dustin A. Hatley
Dustin A. Hatley
/s/ Jeffrey L. Berenson
Jeffrey L. Berenson
/s/ Michael A. Cawley
Michael A. Cawley
/s/ Edward F. Cox
Edward F. Cox
/s/ James E. Craddock
James E. Craddock
/s/ Thomas J. Edelman
Thomas J. Edelman
/s/ Kirby L. Hedrick
Kirby L. Hedrick
/s/ Holli C. Ladhani
Holli C. Ladhani
/s/ Scott D. Urban
Scott D. Urban
/s/ William T. Van Kleef
William T. Van Kleef
/s/ Molly K. Williamson
Molly K. Williamson
Chairman of the Board, President and Chief Executive
Officer
(Principal Executive Officer)
February 20, 2018
Executive Vice President, Chief Financial Officer
February 20, 2018
(Principal Financial Officer)
Vice President, Chief Accounting Officer and Controller
February 20, 2018
(Principal Accounting Officer)
Director
Director
Director
Director
Director
Director
Director
Director
Director
February 20, 2018
February 20, 2018
February 20, 2018
February 20, 2018
February 20, 2018
February 20, 2018
February 20, 2018
February 20, 2018
February 20, 2018
Director
February 20, 2018
162
Directors
Executive Officers
General Information
Annual Meeting
The Annual Meeting of Stockholders of Noble
Energy, Inc. will be held on April 24, 2018, at 9:30
a.m. Central Time, at The St. Regis, 1919 Briar Oaks
Lane, Houston, Texas 77027
All stockholders are cordially invited to attend.
Form 10-K
The company’s Annual Report on Form 10-K for the
year ended on December 31, 2017, as filed with
the Securities and Exchange Commission (SEC),
is included in this report. Additional copies are
available without charge upon request by writing
to: Investor Relations, Noble Energy, Inc., 1001
Noble Energy Way, Houston, Texas 77070; via the
company’s website: www.nblenergy.com; or via the
SEC’s website: www.sec.gov.
Noble Energy, Inc. Corporate Headquarters
1001 Noble Energy Way, Houston, Texas 77070
281.872.3100, www.nblenergy.com
Investor Relations
Brad Whitmarsh, Vice President, Investor Relations
281.872.3100, investor_relations@nblenergy.com
Communications and Media Relations
Ben Dillon, Vice President, Communications and
Government Relations, 281.872.3100,
media@nblenergy.com
Independent Public Accountants
KPMG LLP
Transfer Agent and Registrar
Wells Fargo Bank, N.A., Shareowner Services,
P.O. Box 64854, St. Paul, MN 55164-0854
800.468.9716, www.shareowneronline.com
Common Stock Listed
New York Stock Exhange, Symbol – NBL
David L. Stover •
Chairman, President and
Chief Executive Officer,
Noble Energy, Inc.
Jeffrey L. Berenson • •
Chairman and Chief
Executive Officer,
Berenson Holdings LLC
Michael A. Cawley • •
President and Manager,
The Cawley Consulting
Group, LLC
Edward F. Cox • • •
Chair, New York Republican
State Committee
James E. Craddock • • •
Former Chief Executive
Officer, Rosetta
Resources Inc.
Thomas J. Edelman • • •
Managing Partner,
White Deer Energy LP
Kirby L. Hedrick • • •
Former Executive Vice
President, Phillips Petroleum
Company
Holli C. Landhani •
President and CEO,
Select Energy Services, Inc.
Scott D. Urban • • •
Partner, Edgewater
Energy LLC
William T. Van Kleef • •
Former Executive Vice
President and Chief
Operating Officer,
Tesoro Corporation
Molly K. Williamson • • •
Scholar with Middle
East Institute
_______________
Committee Membership
• Audit Committee
• Compensation, Benefits
and Stock Option
Committee
• Corporate Governance and
Nominating Committee
• Environment, Health and
Safety Committee
Departs Noble Energy
Board of Directors April 2018
David L. Stover
Chairman, President and
Chief Executive Officer
Kenneth M. Fisher
Executive Vice President
and Chief Financial Officer
Gary W. Willingham
Executive Vice President,
Operations
J. Keith Elliott
Senior Vice President,
Offshore
Terry R. Gerhart
Senior Vice President,
Midstream
John T. Lewis
Senior Vice President,
Corporate Development
Charles J. Rimer
Senior Vice President,
Global Services
A. Lee Robison
Senior Vice President,
Human Resources and
Administration
T. Hodge Walker
Senior Vice President,
U.S. Onshore
_______________
Forward-Looking
Statements
This 2017 Annual Report to
Stockholders contains forward-
looking statements based
on expectations, estimates
and projections as of the
date of this report. These
statements by their nature are
subject to risks, uncertainties
and assumptions and are
influenced by various factors.
As a consequence, actual
results may differ materially
from those expressed in the
forward-looking statements.
For more information, see
“Disclosure Regarding
Forward-Looking Statements”
in Noble Energy’s Form 10-K
included in this report.
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