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, 2012
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)
100 Glenborough Drive, Suite 100
Houston, Texas
(Address of principal executive offices)
73-0785597
(I.R.S. employer identification number)
77067
(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 or a smaller reporting
company. See definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
(Check one):
Large accelerated filer
Accelerated filer
Non-accelerated filer
(Do not check if a smaller reporting company)
Smaller reporting company
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, 2012: $15.1 billion.
Number of shares of Common Stock outstanding as of January 18, 2013: 178,714,869.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive proxy statement for the 2013 Annual Meeting of Stockholders to be held on April 23, 2013, which will
be filed with the Securities and Exchange Commission within 120 days after December 31, 2012, are incorporated by reference into Part III.
TABLE OF CONTENTS
PART I
Items 1. and 2.
Item 1A.
Item 1B.
Item 3.
Item 4.
Business and Properties ..............................................................................................................................
Risk Factors ................................................................................................................................................
Unresolved Staff Comments.......................................................................................................................
Legal Proceedings.......................................................................................................................................
Mine Safety Disclosures .............................................................................................................................
Executive Officers ......................................................................................................................................
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.
PART II
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.....................................................................................................
PART IV
3
34
55
56
56
56
58
61
62
98
100
159
159
159
160
160
160
160
160
Item 15.
Exhibits, Financial Statements Schedules ..................................................................................................
160
In this report, the following abbreviations are used:
GLOSSARY
Bbl
BBoe
Bcf
Bcf/d
BCM
BOE
Boe/d
Btu
FPSO
GHG
HH
LNG
LPG
MBbl/d
MBoe/d
Mcf
MMBbls
MMBoe
MMBtu
MMBtu/d
MMcf/d
MMcfe/d
MMgal
NGL
NYMEX
PSC
Tcf
US GAAP
WTI
Barrel
Billion barrels oil equivalent
Billion cubic feet
Billion cubic feet per day
Billion cubic meter
Barrels oil equivalent. Natural gas is converted on the basis of six Mcf of gas per one barrel of 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 oil equivalent for natural gas is significantly less than
the price for a barrel of oil.
Barrels oil equivalent per day
British thermal unit
Floating production, storage and offloading vessel
Greenhouse gas emissions
Henry Hub index
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
Production sharing contract
Trillion cubic feet
United States generally accepted accounting principles
West Texas Intermediate index
PART I
Items 1. and 2. Business and Properties
This Annual Report on Form 10-K and the documents incorporated herein by reference contain forward-looking statements
based on expectations, estimates and projections as of the date of this filing. 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. See Item 1A. Risk Factors – Disclosure Regarding
Forward-Looking Statements of this Form 10-K.
General
Noble Energy, Inc. (Noble Energy, the Company, we or us) is a leading independent energy company engaged in worldwide oil
and gas exploration and production. Founded by Lloyd Noble in 1932, we recently celebrated the 80th anniversary of our
founding. 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 S&P 500.
Our purpose, Energizing the World, Bettering People's Lives®, reflects our commitment to deliver energy through crude oil and
natural gas exploration and production while embracing our responsibility to be a good corporate citizen and 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, lead our industry, respect our environment and care for our people and the
communities where we operate. In 2012, we published our first Sustainability Report.
We aim to achieve sustainable growth in value and cash flow through exploration success and the development of a high-
quality, diversified and growing portfolio of assets that is balanced between US and international projects. Exploration success,
along with additional capital investment in the US and in international locations such as West Africa and the Eastern
Mediterranean, has resulted in a visible lineup of major development projects which positions us for substantial future reserves,
production and cash flow growth. Occasional strategic acquisitions of producing and non-producing properties, combined with
the periodic divestment of non-core assets, have allowed us to achieve our objective of a diversified, growing asset portfolio
offering superior returns to investors.
Our portfolio is diversified between short-term and long-term projects, both onshore and offshore, domestic and international.
Our organization and business model is focused on sustainable, high return growth through the pursuit of material exploration
opportunities which can be monetized on a competitive discovery-to-production cycle through highly capable major
development project execution. Our first major offshore development project, Aseng, offshore Equatorial Guinea, began
production in late 2011. We followed our success at Aseng with our second major development project, Galapagos, in the
deepwater Gulf of Mexico, which began commercial crude oil production in June 2012. We remain on schedule with two major
development projects, Tamar, offshore Israel, and Alen, offshore Equatorial Guinea, scheduled to begin commercial production
in the second and third quarters of 2013, respectively. Our ability to deliver these major development projects on schedule and
budget provides a competitive and financial advantage in the industry.
Onshore US assets provide a stable base of production along with growing development programs and accommodate flexible
capital spending programs that can be adjusted in response to ongoing changes in the economic environment. We continue to
enhance project performance through technology and operational efficiency. Our long-term offshore development projects,
while requiring multi-year capital investment, are expected to offer superior financial returns and cash flow coupled with
sustained production. Our portfolio offers a diverse production mix among crude oil, US natural gas, and international natural
gas.
We have operations in five core areas:
•
•
•
•
•
the DJ Basin (onshore US);
the Marcellus Shale (onshore US);
the deepwater Gulf of Mexico (offshore US);
offshore West Africa; and
offshore Eastern Mediterranean.
These five core areas provide:
•
•
•
the majority of our crude oil and natural gas production;
visible growth from major development projects; and
numerous exploration opportunities.
3
Our growth is supported by a strong balance sheet and liquidity levels. We strive to deliver competitive returns and a growing
dividend. Our cash dividends have increased 38% in the last five years, from 66 cents per share in 2008 to 91 cents per share in
2012. See Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities - Stock Performance Graph and Item 6. Selected Financial Data for additional financial and operating information
for fiscal years 2008-2012.
In this report, unless otherwise indicated or where the context otherwise requires, information includes that of Noble Energy
and its subsidiaries. All references to production, sales volumes and reserves quantities are net to our interest unless otherwise
indicated.
Major Development Project Inventory We are moving forward on a number of major development projects, many of which
have resulted from our exploration success. Each project will progress, as appropriate, through the various development phases
including appraisal and development drilling, front-end engineering and design, construction and exploitation. We currently
have projects in all phases of the development cycle with some contributing production growth in 2012 and 2013, and others
we are working to sanction with final investment decisions targeting first production from 2015 and beyond. Although these
projects will require significant capital investments over the next several years, they typically offer long-life, sustained cash
flows after investment and attractive financial returns. Our major development projects resulting from exploration success and
strategic acquisitions include the following:
Sanctioned Projects
Unsanctioned Projects
· Horizontal Niobrara (onshore US)
· Marcellus Shale (onshore US)
· Tamar (offshore Israel)
· Alen (offshore Equatorial Guinea)
· Gunflint (deepwater Gulf of Mexico)
· Big Bend (deepwater Gulf of Mexico)
· Leviathan (offshore Israel)
· Cyprus (offshore Cyprus)
· Carla and Diega (offshore Equatorial Guinea)
· West Africa gas project (offshore Equatorial Guinea)
These projects are discussed in more detail in the sections below. See also Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operations – Operating Outlook – Major Development Project Inventory.
Proved Oil and Gas Reserves Proved reserves at December 31, 2012 were as follows:
Summary of 2012 Oil and Gas Reserves as of Fiscal-Year End
Based on Average 2012 Fiscal-Year Prices
December 31, 2012
Proved Reserves
Crude Oil,
Condensate
& NGLs
(MMBbls)
Natural Gas
(Bcf)
Total
(MMBoe)
130
60
—
8
198
114
40
3
2
159
357
1,042
514
18
8
1,582
945
204
2,232
1
3,382
4,964
303
146
3
9
461
272
74
375
2
723
1,184
Reserves Category
Proved Developed
United States
Equatorial Guinea
Israel
Other International (1)
Total Proved Developed Reserves
Proved Undeveloped
United States
Equatorial Guinea
Israel
Other International (1)
Total Proved Undeveloped Reserves
Total Proved Reserves
(1) Other international includes the North Sea and China.
4
Total proved reserves as of December 31, 2012 were approximately 1.2 BBoe, a 2% decrease from 2011. US proved reserves
accounted for 49% of the total, and international proved reserves accounted for 51%. Our 2012 proved reserves mix is 30%
global liquids, 42% international natural gas, and 28% 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.
Crude Oil and Natural 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. These activities include
geophysical and geological evaluation and exploratory drilling, where appropriate. Our properties consist primarily of interests
in developed and undeveloped crude oil and natural gas leases and concessions. We also own natural gas processing plants and
natural gas gathering and other crude oil and natural gas-related pipeline systems which are primarily used in the processing
and transportation of our crude oil, natural gas and NGL production.
Exploration Activities We primarily focus on organic growth from exploration and development drilling, concentrating on
basins or plays where we have strategic competitive advantages, such as proprietary seismic data and operational expertise, and
which we believe generate superior returns. We have had substantial exploration success onshore US and in the deepwater Gulf
of Mexico, the Douala Basin offshore West Africa and the Levant Basin offshore Eastern Mediterranean, resulting in our
significant portfolio of major development projects. We have numerous exploration opportunities remaining in these areas and
are also engaged in new venture activity in both the US and international locations. Our focus on exploration activities has
created a sustainable industry-leading exploration program. During 2012, we expanded our global presence by entering into
three new areas, onshore Northeast Nevada, offshore Falkland Islands and offshore Sierra Leone.
Appraisal, Development and Exploitation Activities Our exploration success and strategic acquisitions have provided us
with numerous appraisal, development, and exploitation opportunities, as demonstrated in our growing inventory of major
development projects. In 2012, we commenced crude oil production from Galapagos, deepwater Gulf of Mexico, our second
major offshore development project, brought online following the start up of Aseng in 2011. Additionally, we continued to
make significant progress on our other major development projects.
Acquisition and Divestiture Activities We maintain an ongoing portfolio management program. Accordingly, we may 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 owning the assets. We may also periodically divest non-core, non-strategic assets in order to optimize
our asset portfolio.
Strategic Partner for Leviathan The Leviathan field, offshore Israel, is the largest conventional natural gas discovery in our
history, with resources sufficient for both domestic demand and export. During 2012, we and our existing partners in the
Leviathan project commenced a process to identify a partner who could provide technical and financial support as well as
midstream and downstream expertise. On December 2, 2012, we and our existing partners announced that we had agreed in
principle on a proposal to sell a 30% working interest in the Leviathan licenses to Woodside Energy Ltd. (Woodside). Woodside
is Australia's largest producer of LNG with over 25 years of experience and has strong working relationships with many
potential customers in the Asian LNG markets. We expect to execute a final agreement with Woodside during the first half of
2013. See Eastern Mediterranean (Israel and Cyprus) - Woodside Agreement, below.
Non-Core Divestiture Program Our non-core divestiture program is designed to generate organizational and operational
efficiencies as well as cash for use in our capital investment program. Divestitures of non-core properties allow us to allocate
capital and employee resources to high-growth, superior return areas. Proceeds from divestitures provide additional flexibility
in the implementation of our international exploration and development programs and the acceleration of horizontal drilling
activities in the DJ Basin and Marcellus Shale. During 2012, divestitures generated net proceeds of approximately $1.2 billion.
On August 13, 2012, we sold our 30% non-operated working interests in the Dumbarton and Lochranza fields, located in the
UK sector of the North Sea, for $117 million, after final closing adjustments from the January 1, 2012 effective date. Net daily
production from these properties was approximately 5 MBoe/d at the time of the sale.
During the third quarter of 2012, we closed on three sales of onshore US properties in Kansas, western Oklahoma, western
Texas, and the Texas Panhandle for total proceeds of $1.0 billion. The properties included our interests in about 1,400
producing wells on approximately 109,000 net acres. As of the effective date, April 1, 2012, net daily production on these
properties was approximately 12.5 MBoe/d.
We sold approximately 57 MMBoe of proved reserves in 2012 and continue to market packages of non-core onshore US
properties and our remaining North Sea properties.
Entry into Falkland Islands Joint Venture In August 2012, we entered into an agreement with Falkland Oil and Gas Limited
(FOGL) and subsequently acquired an interest in FOGL's extensive license areas consisting of approximately 10 million
undeveloped acres, gross, located south and east of the Falkland Islands.
5
Entry into Sierra Leone In September 2012, the Government of Sierra Leone awarded us participation in two offshore
exploration blocks, SL 8A-10 and SL 8B-10, covering almost 1.4 million acres, gross. Under the terms of the award, Chevron
(SL) Ltd. will be the operator and we will have a non-operated 30% working interest.
Exit from Senegal/Guinea-Bissau In 2012, we decided not to continue to participate in further appraisal activities and
relinquished our acreage.
Exit from Ecuador In May 2011, we transferred our assets in Ecuador to the Ecuadorian government. We received cash
proceeds of $73 million for the transfer of our offshore Amistad field assets, onshore gas processing facilities, Block 3 PSC and
the assignment of the Machala Power electricity concession and its associated assets. Our net book value for the assets had
been reduced due to previous impairment charges, resulting in a pre-tax gain of $25 million.
Entry into Marcellus Shale Joint Venture On September 30, 2011, we entered into an agreement with a subsidiary of CONSOL
Energy Inc. (CONSOL) to jointly develop oil and gas assets in the Marcellus Shale areas of southwest Pennsylvania and
northwest West Virginia. The Marcellus Shale joint venture strengthens and diversifies our portfolio, providing a new, material
growth area, which we believe will contribute to future reserves, production, and cash flows. This transaction complements
and further strengthens our US portfolio by adding a high-quality asset, with substantial growth potential that is close to the
US’s largest gas market, the Northeast US. It significantly increases our inventory of low risk, repeatable development projects
while exposing us to more US unconventional resources. The Marcellus Shale joint venture, combined with our other domestic
projects in the DJ Basin and the deepwater Gulf of Mexico, provides diversity to our rapidly expanding international programs.
DJ Basin Asset Acquisition In March 2010, we acquired substantially all of the US Rocky Mountain oil and gas assets of
Petro-Canada Resources (USA) Inc. and Suncor Energy (Natural Gas) America Inc. for a total purchase price of $498 million.
The acquisition included properties located in the DJ Basin, one of our core operating areas.
Onshore US Sale In August 2010, we closed the sale of non-core assets in the Mid-Continent and Illinois Basin areas for cash
proceeds of $552 million and recorded a gain of $110 million.
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 3. Acquisitions and Divestitures.
Asset Impairments During 2012, we recorded impairment charges of $104 million, related to our South Raton and Piceance
developments due to near-term declines in crude oil and natural gas prices, respectively, and our Mari-B, Pinnacles and Noa
fields, offshore Israel, due to end-of-field life declines in production. See Item 8. Financial Statements and Supplementary
Data – Note 4. Asset Impairments.
United States
We have been engaged in crude oil and natural gas exploration, exploitation and development activities throughout onshore US
since 1932 and in the Gulf of Mexico since 1968. US operations accounted for 60% of 2012 total consolidated sales volumes
and 49% of total proved reserves at December 31, 2012. Approximately 58% of the proved reserves are natural gas and 42%
are crude oil, condensate and NGLs.
Sales of production and estimates of proved reserves for our US operating areas were as follows:
Year Ended December 31, 2012
Sales Volumes
December 31, 2012
Proved Reserves
Crude Oil
&
Condensate
(MBbl/d)
32
—
2
14
1
49
Natural
Gas
(MMcf/d)
194
90
117
NGLs
Total
(MBbl/d)
13
—
2
(MBoe/d)
77
15
24
Crude Oil
&
Condensate
(MMBbls)
150
—
—
14
23
438
1
—
16
18
5
139
19
3
172
Natural
Gas
(Bcf)
880
827
203
21
56
1,987
NGLs
Total
(MMBbls)
61
8
3
(MMBoe)
358
146
37
—
—
72
23
11
575
Wattenberg
Marcellus Shale
Rockies
Deepwater Gulf of
Mexico
Gulf Coast and Other
Total
6
Wells drilled in 2012 and productive wells at December 31, 2012 for our US operating areas were as follows:
Wattenberg
Marcellus Shale
Rockies
Deepwater Gulf of Mexico
Gulf Coast and Other
Total
Year Ended
December 31, 2012
December 31,
2012
Gross Wells Drilled
or Participated in (1)
555
71
24
1
—
651
Gross Productive
Wells
8,954
173
4,210
11
313
13,661
(1)
Excludes exploratory wells drilled and suspended awaiting a sanctioned development plan or being evaluated to assess the economic
viability of the well. See Drilling Activity below.
Locations of our onshore US operations as of December 31, 2012 are shown on the map below:
DJ Basin / Wattenberg The DJ Basin, where we have an acreage position of approximately 750,000 net acres, is a premier US
crude oil resource play and is significant to our production growth and development activities. Included in the DJ Basin is
Wattenberg (approximately 95% operated working interest), our largest onshore US asset, where we have a multi-year project
inventory. In 2012, we continued to improve our operational performance while accelerating our drilling activities. During
2012, we had record sales volumes in the DJ Basin due to continued strong performance from our horizontal drilling program
that began in 2010.
Wattenberg includes:
•
•
the Greater Wattenberg Area (GWA), where we have conducted substantial vertical development over the last several
years as well as successful horizontal drilling in the high density area and more recently in the less developed
northeastern part of GWA. The area is comprised of both an expanding crude oil window to the northeast and strong
natural gas window in the core and to the southwest; and
northern Colorado from the edge of the GWA to the Wyoming border where we expanded our acreage position and
drilled over 25 wells during 2012.
7
During 2012, we spud a total of 410 development wells in Wattenberg, of which 195 were horizontal wells into the Niobrara
and Codell formations. In 2011, we began constructing multi-well horizontal drilling pads and centralized production facilities
to minimize our surface use (EcoNode). The EcoNode allows for more efficient execution and operations by reducing our land
use and surface traffic, water usage and moving the program forward with less surface impact. We continue to evaluate impacts
of changes in well spacing and pad design. Included in the well numbers above, we spud 10 extended-reach (7,000 - 9,000 feet)
lateral wells as part of the 2012 drilling program and are planning for approximately 20% of our 2013 drilling program to be
extended-reach wells.
Wattenberg contributed an average of 77 MBoe/d of sales volumes, represented approximately 33% of total consolidated sales
volumes in 2012, with approximately 58% being liquids, and approximately 358 MMBoe or 31% of total proved reserves at
December 31, 2012. Horizontal drilling in the Niobrara formation has significantly expanded the economic limits of this field.
Of the net sales volumes from Wattenberg, approximately 28 MBoe/d, came from a total of 279 producing wells in our
horizontal Niobrara program.
During 2012, we continued to expand our horizontal Niobrara development activities into Northern Colorado, where recent
results indicate recoveries comparable to those in the GWA. We added almost 26,000 net acres to our Northern Colorado
position this year, increasing our acreage position to approximately 230,000 net acres. We expect to spud approximately 80 to
90 wells in this area during 2013, further accelerating our horizontal Niobrara development.
Our 2012 Wattenberg development program resulted in additions to proved reserves of approximately 55 MMBoe,
approximately 72% of which are liquids.
Our DJ Basin position gives us opportunities to expand beyond our GWA development activities. We have also expanded into
Wyoming and continue to appraise this acreage.
Marcellus Shale A joint venture partnership with CONSOL Energy Inc. (CONSOL), formed in September 2011, the Marcellus
Shale represents our second onshore US core area. We hold a 50% interest in approximately 628,000 net acres in southwest
Pennsylvania and northwest West Virginia. We operate the wet gas development area while CONSOL operates the dry gas
development area.
During 2012, we drilled to total depths approximately 25 wet gas wells and began wet gas production in July 2012. By
applying our DJ Basin experience, we continue to test the limits of our recovery techniques with longer lateral wells, improved
hydraulic fracturing design and optimal well placements. As we move into new areas, water supply and gas gathering
infrastructure are expanding. Our partner, CONSOL, drilled to total depths 64 dry gas wells during 2012. Although we have
reduced drilling in the dry gas area due to the low natural gas price environment, the dry gas portion of the program continues
to deliver economically attractive returns due to strong production performance, high net revenue interests, competitive costs,
partner alignment, and access to the US's largest gas market in the Northeast.
The Marcellus Shale contributed an average of 15 MBoe/d of sales volumes and represented approximately 6% of total
consolidated sales volumes in 2012, with approximately 1% being liquids, and approximately 146 MMBoe or 12% of total
proved reserves at December 31, 2012.
Our joint development plan for 2013 projects that we will drill to total depth approximately 90 horizontal wells in the wet gas
areas and CONSOL will drill to total depth approximately 36 horizontal wells focused in the dry gas areas of the Marcellus
Shale.
The large portion of acreage that is currently held by production should allow for efficient development utilizing pad drilling.
Pad drilling minimizes our surface use as well as the permitting and infrastructure requirements.
Hydraulic Fracturing We find that the use of hydraulic fracturing is necessary to produce commercial quantities of crude oil
and natural gas from many reservoirs, including the DJ Basin and the Marcellus Shale. Hydraulic fracturing involves the
injection of a mixture of pressurized water, sand and a small amount of chemicals into rock formations in order to stimulate
production of natural gas and/or oil from dense subsurface rock formations, including shale. The majority of our onshore US
proved undeveloped reserves, which totaled 265 MMBoe at December 31, 2012, will require the use of hydraulic fracturing to
produce commercial quantities of crude oil and natural gas. See Hydraulic Fracturing, below, for more discussion.
Natural Gas Flaring The practice of natural gas flaring (burning) is the safest way to dispose of natural gas associated with
crude oil production when no gas infrastructure is available. The volume of natural gas being flared is growing in certain areas
of the US, such as the Bakken Shale, primarily as a result of increased oil shale drilling activity and limited natural gas
infrastructure. In these areas, public concern has grown about the potential impact of GHG emissions from flaring on the
environment, as well as the potential waste of natural resources.
In our DJ Basin and Marcellus Shale operations, natural gas infrastructure build out generally occurs in advance of drilling
activity. If short-term flaring is necessary, we use efficient, environmentally protective and energy-saving flaring technologies.
We participate in the Carbon Disclosure Project by publicly disclosing, on a voluntary basis, information pertaining to our
GHG emissions.
8
Northeast Nevada We constantly strive to identify new onshore exploration opportunities with reasonable entry cost,
significant running room and the potential to become a new core area. We have a 350,000 net acre position (66% fee acreage
and remainder federal acreage) in Northeast Nevada, prospective for oil exploration, which we identified through basin scale
reconnaissance and innovative geoscience concepts. We acquired 3-D seismic over portions of the acreage in 2012 with a
vertical well exploratory drilling program scheduled to begin in 2013.
Other Onshore Properties We also operate in the following onshore US areas: Rocky Mountains including Piceance Basin
(Western Colorado), Bowdoin field (North Central Montana), Tri-State field (Northeastern Colorado, Northwestern Kansas and
Southwestern Nebraska), San Juan Basin (Northwestern New Mexico), and Powder River Basin (North/Central Wyoming); and
Gulf Coast including the Haynesville field (East Texas and North Louisiana) and other properties in Texas and Louisiana. Other
onshore properties accounted for 13% of total consolidated sales volumes in 2012 and 4% of total proved reserves at
December 31, 2012. Although our future development focus is concentrated on our core areas, we continue to produce and
develop in these other areas. We drilled 22 development wells during 2012. During 2012, we completed the sale of various
non-core onshore properties and continue to evaluate the divestment opportunities associated with other non-core properties.
See Acquisition and Divestiture Activities - Non-Core Divestiture Program above.
Deepwater Gulf of Mexico Locations of our deepwater Gulf of Mexico developments as of December 31, 2012 are shown on
the map below:
Noble Energy was one of the first independent producers to explore in the Gulf of Mexico. We acquired our first offshore block
in 1968, and today the deepwater Gulf of Mexico is one of our core operating areas. Our focus is on high-impact opportunities
with the potential to provide significant medium and long-term growth. We have six producing fields, multiple ongoing
development projects and a substantial inventory of exploration opportunities.
The deepwater Gulf of Mexico accounted for 8% of total consolidated sales volumes in 2012 and 2% of total proved reserves at
December 31, 2012. We currently hold leases on 102 deepwater Gulf of Mexico blocks, representing approximately 596,000
gross acres (414,000 net acres). Of our total gross acres, approximately 96,000 gross acres (41,000 net acres) have been
developed. We are the operator on approximately 86% of our leases. See also Developed and Undeveloped Acreage - Future
Acreage Expirations, below.
Deepwater Gulf of Mexico Exploration Program Our deepwater Gulf of Mexico operations resulted from lease acquisition,
expansion of our 3-D seismic database, and an active drilling program. We currently have an inventory of 31 identified
prospects, which are a combination of both high impact stand-alone subsalt prospects and smaller, high value tie-back
opportunities. The prospects are subject to an ongoing rigorous technical maturation process and may or may not emerge as
drillable options. To support the future exploration, appraisal, and development work, we have the ENSCO 8501 rig under
contract through most of 2013 with four additional one year option elections. We also have the ENSCO 8505 rig under contract
through 2014 in a rig share agreement with two other operators; however, we farmed out our 2013 drilling slot to our rig
partners. In 2013, we plan to drill a Gunflint appraisal well and at least one exploration well.
9
Big Bend During 2012, we drilled the successful Big Bend exploration well. The well is located in Mississippi Canyon Block
698 and was drilled to a total depth of 15,989 feet. We hold a 54% operated working interest in Big Bend. Logging results
identified approximately 150 feet of net oil pay in two high-quality reservoirs. We anticipate sanctioning a development plan
for Big Bend during 2013 with first production targeted in late 2015 or early 2016.
Our most significant deepwater Gulf of Mexico properties and current development plans are discussed in more detail below.
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
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. During 2012, we completed the subsea tieback to the nearby
Nakika production platform and began production in June. The Galapagos development has significantly increased our offshore
production in 2012 with flow rates up to approximately 13.5 MBoe/d, net.
Gunflint (Mississippi Canyon Block 948; 26% operated working interest) Gunflint is a 2008 crude oil discovery, our largest
deepwater Gulf of Mexico discovery to date. In July 2012, we drilled a successful Gunflint appraisal well. During first quarter
of 2013, we plan to drill our second appraisal well targeting the southern area of the reservoir. Front-end conceptual studies
have been completed, and we are working toward sanctioning of a scalable development project in 2013. We are currently
targeting 2017 for production start-up utilizing a standalone facility. If we choose to connect to an existing third-party host, the
project could have an accelerated completion schedule.
Raton/South Raton (Mississippi Canyon Blocks 248 and 292) Raton (67% operated working interest) was a 2006 natural gas
discovery and has been producing since 2008. South Raton (79% operated working interest) was a 2008 crude oil discovery.
During the second quarter of 2012, the South Raton crude oil development project commenced production at approximately 3
MBbl/d, net. South Raton is tied back to a non-operated host facility. We are currently evaluating mechanical issues at South
Raton, which is temporarily offline.
Swordfish (Viosca Knoll Blocks 917, 961 and 962; 85% operated working interest) Swordfish was a 2001 crude oil discovery
and began producing in 2005. The Swordfish project currently includes two producing wells connected to a third-party
production facility through subsea tiebacks.
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 three producing wells connected to existing infrastructure through
subsea tiebacks.
Lorien (Green Canyon Block 199; 60% operated working interest) Lorien was a 2003 crude oil discovery and began
producing in 2006. The project currently includes one producing well connected to existing infrastructure through subea
tiebacks.
International
Our international business focuses on offshore opportunities in multiple countries and provides diversity to our portfolio.
Development projects in Equatorial Guinea, Israel, the North Sea, and China have contributed substantially to our growth over
the last decade.
Significant recent exploration successes offshore West Africa, Israel and Cyprus have identified multiple major development
projects that are expected to contribute to production growth in the future. We have large acreage positions in West Africa, the
Eastern Mediterranean, and in 2012 we entered two new areas: offshore the Falkland Islands and offshore Sierra Leone. Each of
these locations will provide further international exploration opportunities.
In furtherance of our commitment to global offshore exploration and development, on September 27, 2012, we announced that
we have entered into a 36-month drilling services contract with a subsidiary of Atwood Oceanics, Inc. Drilling services will be
provided by a new-build drillship, the Atwood Advantage. The Atwood Advantage is currently under construction by Daewoo
Shipbuilding & Marine Engineering Co., Ltd. in South Korea. The drillship will be equipped with enhanced offline capabilities,
such as dual blowout preventer stacks that allow for simultaneous inspection and drilling activities, and will be rated for
operations in 12,000 feet water depth/40,000 feet drill depth. The increased mobility of the Atwood Advantage, as compared
with other drilling rigs, will add flexibility to our global exploration program. We expect that the drillship will be available
fourth quarter 2013 and initially deployed offshore Israel.
International operations accounted for 40% of total consolidated sales volumes in 2012 and 51% of total proved reserves at
December 31, 2012. International proved reserves are approximately 81% natural gas and 19% crude oil and condensate.
Operations in China, Cyprus, Equatorial Guinea, and Sierra Leone are conducted in accordance with the terms of PSCs. In
Cameroon, we operate in accordance with the terms of a PSC and a mining concession. Operations in Nicaragua, the Falkland
Islands, the North Sea, Israel, and other foreign locations are conducted in accordance with concession agreements, permits or
licenses.
10
Locations of our international operations are shown on the map below:
Sales volumes and estimates of proved reserves for our international operating areas were as follows:
Year Ended December 31, 2012
Sales Volumes
December 31, 2012
Proved Reserves
Crude Oil
&
Condensate Natural Gas
(MMcf/d)
(MBbl/d)
NGLs
(MBbl/d)
Total
(MBoe/d)
Crude Oil,
Condensate
& NGLs
(MMBbls)
Natural
Gas
(Bcf)
Total
(MMBoe)
International
Equatorial Guinea
Israel
China
Total International
Equity Investee
Discontinued
Operations (North Sea)
Total
Equity Investee Share of Methanol Sales (MMgal)
33
—
4
37
2
5
44
235
101
—
336
—
4
340
—
—
—
—
5
—
5
72
17
4
93
7
5
105
156
100
3
7
110
—
3
113
718
2,250
2
2,970
—
7
2,977
220
378
7
605
—
4
609
11
Wells drilled in 2012 and productive wells at December 31, 2012 in our international operating areas were as follows:
International
Equatorial Guinea
Cameroon
Israel
North Sea
China
Total International
Year Ended
December 31, 2012
Gross Wells Drilled
or Participated in (1)
December 31,
2012
Gross
Productive
Wells
4
1
8
—
3
16
23
—
9
18
28
78
(1)
Excludes exploratory wells drilled and suspended awaiting a sanctioned development plan or being evaluated to assess the economic
viability of the well. See Drilling Activity below.
West Africa (Equatorial Guinea, Cameroon and Sierra Leone) West Africa is one of our core operating areas and includes
the Alba field, Block O and Block I offshore Equatorial Guinea, as well as the YoYo mining concession and Tilapia PSC
offshore Cameroon and two new blocks offshore Sierra Leone. Equatorial Guinea, the only producing country in our West
Africa segment, accounted for approximately 31% of 2012 total consolidated sales volumes and 18% of total proved reserves at
December 31, 2012. At December 31, 2012, we held approximately 119,000 net developed acres and 80,000 net undeveloped
acres in Equatorial Guinea, 542,000 net undeveloped acres in Cameroon, and 414,000 net undeveloped acres in Sierra Leone.
Locations of our operations in West Africa are shown on the map below:
Aseng Project Aseng is a crude oil development project on Block I (38% operated working interest) which includes five
horizontal wells flowing to an FPSO (Aseng FPSO) where the production stream is separated. The oil is stored on the Aseng
FPSO until sold, while the natural gas and water are reinjected into the reservoir to maintain pressure and maximize oil
recoveries. We are the technical operator of the Aseng Project and have executed a crude oil sale, purchase, and marketing
agreement with Glencore Energy UK Ltd. for our share of Aseng production.
The Aseng FPSO is designed to act as an oil production hub, as well as liquids storage and offloading hub, with capabilities to
support future subsea oil field developments in the area. It also has the ability to process and store stabilized condensate from
gas condensate fields in the area, the first of which will be Alen during the third quarter of 2013. It is capable of processing 120
MBbl/d of liquids, including 80 MBbl/d of oil, and reinjecting 160 MMcf/d of natural gas. The Aseng FPSO has storage
capacity of approximately 1.6 MMBbls of liquids.
12
During 2012, Aseng maintained excellent reliability and safety performance and averaged almost 100% production uptime,
while producing on average 62 MBbl/d, 21 MBbl/d net, to Noble Energy.
Alba Field We have a 34% non-operated working interest in the Alba field, offshore Equatorial Guinea, which has been
producing since 1991. Operations include the Alba field and related production and condensate storage facilities, an LPG
processing plant where additional condensate is extracted along with LPGs, and a methanol plant capable of producing up to
3,100 metric tons per day, gross. The LPG processing plant and the methanol plant are located on Bioko Island, Equatorial
Guinea.
We sell our share of natural gas production from the Alba field to the LPG plant, the methanol plant and an unaffiliated LNG
plant. The LPG plant is owned by Alba Plant LLC (Alba Plant), in which we have a 28% interest accounted for as an equity
method investment. The methanol plant is owned by Atlantic Methanol Production Company, LLC (AMPCO), in which we
have a 45% interest, also accounted for as an equity method investment. 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 condensate at our marine terminal at prevailing market prices. We sell our share
of condensate produced in the Alba field under short-term contracts at market-based prices.
In December 2012, the Alba compression project was approved. We are beginning the engineering phase for a compression
platform and related in-field connections in early 2013 with an estimated start-up in 2016.
Alen Project Alen, sanctioned in 2010, is located primarily on Block O (45% operated working interest), offshore Equatorial
Guinea, and is our next West Africa major development project. Initial field development will include three production wells
and three subsea natural gas injection wells tied to a processing facility. Produced condensate will be separated and piped to the
Aseng FPSO utilizing the hub we are in the process of building in the region, where it will be held until sold. The associated
natural gas will be reinjected into the reservoir to maintain pressure and maximize liquids recovery. The Alen facilities are
designed to process up to 440 MMcf/d of natural gas and 40 MBbl/d of condensate. We are the technical operator of the Alen
Project.
Alen is progressing ahead of schedule and below budget. The total gross development cost is trending below sanction cost of
$1.4 billion with first production currently expected during the third quarter of 2013 at 18 MBbl/d, net. The sanctioned plan
originally scheduled commencement late fourth quarter of 2013. Significant effort has been placed to remove the risk from the
schedule by completing as much of the field work as possible early in development. The wells are drilled and completed, the
well-protector and jacket are installed, and the flowlines are in place. The final infrastructure, the topsides for the well-protector
platform and the central platform, are expected to arrive in West Africa late March 2013 to begin installation.
Other Block O & I Projects We are continuing our exploration and appraisal efforts offshore Equatorial Guinea, where we
still have numerous opportunities. We continue the appraisal program for our Carla and Diega discoveries, where we have
encountered hydrocarbons in multiple appraisal wells and side-tracks.
During 2012, we identified a crude oil reservoir below the Alen field while drilling additional Carla appraisal wells.
Development plans are being prepared for possible sanctioning of Carla during 2013, which would have a target first
production at 11 MBbl/d, net, in early 2016. Carla further demonstrates the value of the infrastructure we are building that
allows us to have host facilities and tie back additional fields.
We are continuing to review drilling results from our Diega discovery wells, finalizing an appraisal design program, and
continue to evaluate regional development scenarios for the asset. We plan to begin appraisal drilling in the second half of 2013
or early 2014.
West Africa Gas Project We have a natural gas development team working with the Equatorial Guinea Ministry of Mines,
Industry and Energy in evaluating several monetization options for natural gas that would be produced from Blocks O and I.
Cameroon We have an interest in over one million gross acres offshore Cameroon, which include the YoYo mining
concession and Tilapia PSC. We are the operator (50% working interest) in Cameroon. Natural gas and condensate were
discovered in 2007 when we drilled the YoYo-1 exploratory well. During 2012, we drilled the Trema exploration well testing
the Tilapia Block, offshore Cameroon, but did not locate commercial quantities of hydrocarbons. We are currently evaluating
prospects as a follow-up for our offshore Cameroon exploration program.
Sierra Leone During 2012, the Government of Sierra Leone awarded us participation in two offshore exploration blocks, SL
8A-10 and SL 8B-10, covering almost 1.4 million gross acres. Under the terms of the award, Chevron (SL) Ltd. will be the operator
and we will have a non-operated 30% working interest. We plan to begin acquiring 2-D seismic information over portions of the
acreage in 2013 to assist with our 3-D seismic plans. See Item 1A. Risk Factors - Our entry into new exploration ventures in areas
in which we have no prior experience subjects us to additional risks.
13
Senegal/Guinea-Bissau During 2011, we farmed into the AGC Profond block (30% non-operated working interest) and the
joint venture drilled the Kora-1 exploration well. The well did not result in commercial quantities of hydrocarbons. During
2012, we decided not to participate in the second appraisal period and relinquished our acreage. The cost associated with the
undeveloped leasehold was charged to exploration expense in third quarter 2012.
Eastern Mediterranean (Israel and Cyprus) Another core operating area is located in the Eastern Mediterranean, where we
have had six consecutive natural gas discoveries in recent years. We are also beginning to explore for potential thermogenic
(crude oil generating) hydrocarbon systems which may exist at greater depths.
Israel, the only producing country in our Eastern Mediterranean segment, accounted for 7% of 2012 total consolidated sales
volumes and 32% of total proved reserves at December 31, 2012. At December 31, 2012, we held approximately 58,000 net
developed acres and 581,000 net undeveloped acres located between 10 and 90 miles offshore Israel in water depths ranging
from 700 feet to 6,500 feet. Our leasehold position in Israel includes four leases and 13 licenses, and we are the operator of the
properties. We also hold a license covering approximately 596,000 net undeveloped acres offshore Cyprus adjacent to our Israel
acreage.
Locations of our operations in the Eastern Mediterranean are shown below:
Domestic Natural Gas Demand As the Israeli economy continues to grow, so does the demand for natural gas, which is
currently used primarily for electricity generation. Demand for natural gas in the industrial sector, including refineries,
chemical, desalination, cement and other plants, is also increasing. These sectors are gaining confidence that a long-term supply
of natural gas will be available and are therefore willing to make the capital investment necessary to convert facilities to use
natural gas. We expect that government requirements for emissions reductions could also drive demand for natural gas as fuel.
Natural Gas Export As discussed below, we have made significant natural gas discoveries in the Eastern Mediterranean.
Although we continue to conduct appraisal activities, we expect that the quantity of natural gas discovered can be used to
satisfy growing domestic demand as well as provide sufficient resources for export. Eastern Mediterranean export projects
would be well positioned to supply growing global natural gas demand, and, as discussed further below, we are considering
multiple options. The government of Israel is in the process of finalizing an export policy. See Regulations - Israeli
Interministerial Committee, below.
14
Tamar Natural Gas Project We discovered the Tamar natural gas field (36% operated working interest), offshore Israel, in the
Levant Basin in 2009. Tamar is one of the world's largest offshore conventional gas discoveries in recent years and is currently
one of our major development projects. We expect first delivery of gas to customers in April 2013, four years from discovery
and two and a half years from project sanction.
Tamar Phase 1 development includes five subsea wells with a combined production capacity of 985 MMcf/d, with identified
expansion capability to approximately 1.5 Bcf/d. The natural gas produced at these wells will flow to a new offshore platform
constructed near the existing Mari-B platform. The natural gas will then be delivered to the existing pipeline that connects the
Mari-B field to the Ashdod onshore terminal. Tamar's 93-mile tieback, originating in a water depth in excess of 5,000 feet, is
the longest subsea tieback in the world.
The Tamar partners have executed numerous gas sale and purchase agreements (Tamar GSPAs) for the initial and expanded
capacity as well as a condensate sales agreement. See International Marketing Activities and Delivery Commitments below. In
addition, a floating LNG (FLNG) project is under evaluation.
Leviathan Natural Gas Project In December 2010, we announced a significant natural gas discovery at the Leviathan-1 well
(39.66% operated working interest) offshore Israel in the Levant Basin. The Leviathan field is the largest discovery in our
history and was the world's largest offshore natural gas discovery in 2010. The Leviathan-2 well was plugged due to wellbore
issues. In 2012, we drilled the successful Leviathan-3 appraisal well and spud the Leviathan-4 appraisal well.
We have project and commercial teams in place and are in the process of screening multiple development concepts. Due to
Leviathan's size, full field development and realization of maximum economic value is expected to require several development
phases.
The Leviathan Phase 1 development concept includes offshore processing at an FPSO, with a production capacity of 1.6 Bcf/d
and a capability to serve both domestic demand and export. Domestic production could begin as early as 2016. This option will
enable us to begin production within three years of license to lease conversion. Phase 2, an additional FPSO, is expected to
have a similar production capacity and capability.
Multiple export options, including onshore LNG, FLNG and pipeline are under evaluation. Timing of project sanction depends
on execution of natural gas sales contracts, determination of an onshore entry point and government approvals.
Woodside Agreement On December 2, 2012, we and our existing partners in the Leviathan project announced that we had
agreed in principle on a proposal to sell a 30% working interest in the Leviathan licenses to Woodside Energy Ltd. Each of the
current Leviathan partners is expected to participate as a seller to Woodside. We expect to convey a 9.66% working interest,
reducing our working interest to 30%, and continue as upstream operator. The transaction is subject to the negotiations and
execution of definitive agreements between the parties, as well as customary approvals, prior to closing.
According to the initial proposal, we would receive net cash payments totaling $464 million, a portion of which would be paid
only upon the occurrence of certain future events. The payments, subject to definitive agreement, include the following:
•
•
•
$287 million initial cash payment payable at closing;
$64 million contingent on the ability to export natural gas; and
$113 million contingent on a final investment decision for an LNG project.
Additional payments, subject to definitive agreement, would include the following:
•
•
a share of Woodside's annual LNG revenue above certain price parameters, subject to a $322 million cap over the life
of the project; and
a drilling carry of up to $16 million on the drilling of the planned Mesozoic oil exploration well.
Including the potential revenue sharing amounts and drilling carry, the implied price for our 9.66% working interest being sold
totals $802 million under the initial proposal. Negotiations continue, and, as a result, this amount could change. We expect to
execute a final agreement with Woodside during the first half of 2013. In conjunction with these negotiations, we are assisting
our current Leviathan partners to obtain appropriate financing for their share of development costs and considering providing a
limited amount of financial backstop to them.
Leviathan-1 Deep (Mesozoic Oil Target) In January 2012, we returned to the Leviathan-1 well and began drilling toward two
deeper intervals in order to evaluate them for the existence of crude oil (Leviathan-1 Deep). In May 2012, due to high well
pressure and the mechanical limits of the wellbore design, we suspended drilling operations. Although the well did not reach
the planned objective, we are encouraged by the possibility of an active thermogenic (crude oil generating) hydrocarbon system
at greater depths within the basin.
15
We will integrate the data from the Leviathan-1 Deep well into our model to update our analysis and design a drilling plan
specifically to test the deep oil concept. We have entered into a contract for drilling services to be provided by the Atwood
Advantage drillship, which will be rated for operations in 12,000 feet water depth/40,000 feet drill depth with the capabilities
necessary to reach the target objective, and plan to begin drilling an exploratory well in the fourth quarter of 2013.
Mari-B, Pinnacles and Noa Fields The Mari-B field (47% operated working interest) was the first offshore natural gas
production facility in Israel and has been producing since 2004. Through December 31, 2012, we have delivered over 420 Bcf
of natural gas, net, to Israeli customers.
During 2011, due to multiple interruptions in imported gas supplies from Egypt, Mari-B natural gas volumes were delivered at
very high rates to support Israel's growing natural gas and power demands. As a result, the Mari-B field experienced
accelerated depletion. In January 2012, we announced a cut back in production at Mari-B to prudently manage the reservoir.
We have been working closely with our Israeli customers to manage demand on the Mari-B field and continue production from
it.
In order to help meet Israeli natural gas demand until the Tamar field begins producing, we completed the Noa (47% operated
working interest) and Pinnacles (47% operated working interest) wells and tied them back to the Mari-B platform. We began
selling natural gas from Noa in June 2012 and Pinnacles in July 2012. At December 31, 2012, we recorded an impairment
charge of $31 million for the combined Mari-B, Noa, and Pinnacles wells due to end-of-field life declines in production. See
Item 8. Financial Statements and Supplementary Financial Data - Note 4. Asset Impairments.
We expect to continue producing from Mari-B, Noa and Pinnacles until production commences at the Tamar field. Once Tamar
begins producing, Mari-B, Noa and Pinnacles production volumes will be reduced, and we plan to transition the Mari-B
reservoir to a natural gas storage facility. We will continue to provide natural gas to Israeli purchasers under several natural gas
sales and purchase agreements for which the total contract quantities have not been met. See Delivery Commitments and Item
1A. Risk Factors - Exploration, development and production risks and natural disasters could result in liability exposure or the
loss of production and revenues.
Other Discoveries Offshore Israel We and our partners are working on a development plan for the Dalit field (36% operated
working interest), a 2009 natural gas discovery. Development would include tie-in to the Tamar platform, and we have
submitted a development plan to the Israeli government. In addition, we are reviewing alternatives for the development of the
Dolphin (39.66% operated working interest) and Tanin 1 (47.06% operated working interest) natural gas discoveries.
Cyprus During the fourth quarter of 2011, we made another natural gas discovery when we drilled the successful A-1
exploration well in Block 12, offshore Cyprus. We are planning to drill an appraisal well in 2013 and are working with the
government of Cyprus on a domestic supply project as well as a potential LNG project. The Turkish government has voiced
opposition to our drilling operations. However, the US and the European Union have expressed support for Cyprus' right to
explore offshore for hydrocarbons in its exclusive economic zone.
Risks Although we will be able to incorporate major development project execution gained on the Aseng and Tamar projects
to Leviathan or other LNG projects, such complex, costly projects as discussed above are not without financial or execution
risk. See item 1A. Risk Factors - The magnitude of our offshore Eastern Mediterranean discoveries will present financial and
technical challenges for us due to the large-scale development requirements and Failure of our partners to fund their share of
development costs or obtain project financing could result in delay or cancellation of future projects, thus limiting our growth
and future cash flows.
See also Item 1A. Risk Factors - Our international operations may be adversely affected by economic and political
developments and 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.
Other International
Our other international operations accounted for 2% of our total consolidated sales volumes for 2012 and 1% of total proved
reserves at December 31, 2012.
Falkland Islands In August 2012, we entered into an agreement with Falkland Oil and Gas Limited (FOGL) to acquire an
interest in FOGL's extensive license areas, consisting of approximately 10 million acres, gross, located south and east of the
Falkland Islands. The Falkland Islands are located in the South Atlantic Ocean approximately 400 miles from the South
America mainland. The agreement was approved by the Falkland Islands Government in October 2012.
Under the agreement we have farmed-in to the Northern and Southern Area Licenses for a 35% working interest. FOGL will
continue as operator until we assume operatorship of the Northern Area License in March 2013 and the Southern Area License
no later than March 2014.
16
Our financial contribution includes 60% of the costs of two commitment wells and a $25 million cash contribution paid in
January 2013. We may also elect to participate in a discretionary exploration well, paying 45% of the costs in return for a 35%
working interest. We expect to invest approximately $180 to $230 million over the next three years.
During fourth quarter 2012, FOGL drilled the Scotia exploration well, which reached its Cretaceous objective in November
2012 and encountered 40 feet of net pay. We are encouraged by the well results. Although we did not see a substantial amount
of the reservoir section, virtually all sandstones with significant porosity in and below the target contained hydrocarbons. We
are currently evaluating the well results and have begun acquiring 3D seismic over the Northern and Southern Area licenses.
The integration of these activities will allow us to assess the economic viability of this prospect. The Scotia well has been
plugged in accordance with the regulations of the Falkland Islands Department of Mineral Resources, which require all
exploration wells, including successful ones, to be plugged.
See Acquisition and Divestiture Activities - Entry into Falkland Islands Joint Venture and Item 1A. Risk Factors - Our entry
into new exploration ventures in areas in which we have no prior experience subjects us to additional risks.
Nicaragua We continue to evaluate our undeveloped acreage and currently plan to spud our first exploration well (Paraiso),
targeting a crude oil play, in the second half of 2013. A 3D seismic survey and further technical work have clarified this
prospect and helped to decrease the risk. We are currently seeking a partner in this prospect, anticipating a working interest
farmout by the time we spud the first exploration well.
China We have been engaged in exploration and development activities in China since 1996 under the terms of a PSC,
expiring in 2018. We are currently negotiating for an extension beyond 2018. We have a 57% non-operated working interest in
the Cheng Dao Xi (CDX) field, which is located in the shallow water of the southern Bohai Bay.
North Sea We have been conducting business in the North Sea (the Netherlands and the United Kingdom (UK)) since 1996.
During 2012, we sold our 30% non-operated working interests in the Dumbarton and Lochranza fields, located in the UK sector
of the North Sea. Also during the fourth quarter of 2012, the nearby Bligh well, a potential co-development candidate for our
Selkirk discovery, was drilled. Bligh encountered hydrocarbons but disappointingly tight non-commercial reservoirs. Therefore,
we determined that the Selkirk field was uneconomic for joint development and wrote it off to exploration expense. Our
remaining North Sea assets are included in assets held for sale in our consolidated balance sheet as of December 31, 2012, and
the North Sea geographical segment has been reported as discontinued operations in our consolidated statements of operations.
See Item 8. Financial Statements and Supplementary Financial Data - Note 3. Acquisitions and Divestitures.
Proved Reserves Disclosures
Internal Controls Over Reserves Estimates Our policies 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;
each field representing more than 1% of total proved reserves, as well as a selection of smaller fields, 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.
In addition, our Company-wide short-term incentive plan does not include quantitative targets for proved reserves additions.
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 Vice President – Strategic Planning, Environmental Analysis & Reserves (Vice President – Reserves) and
certain members of senior management.
Our Vice President – Reserves is the technical person primarily responsible for overseeing the preparation of our reserves
estimates. Our Vice President – Reserves has a Bachelor of Science degree in Engineering and over 25 years of industry
experience with positions of increasing responsibility in engineering and evaluations. The Vice President – Reserves reports
directly to our Chief Executive Officer.
Technologies Used in Reserves Estimation The SEC’s reserves rules expanded the technologies that a company can use to
establish reserves. The SEC now allows 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.
17
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 2012 reserves estimates.
Third-Party Reserves Audit In each of the years 2012, 2011, and 2010, we retained NSAI to perform reserves audits of
proved reserves. The reserves audit for 2012 included a detailed review of eight of our major onshore US, deepwater Gulf of
Mexico and international fields, which covered approximately 87% of US proved reserves and 98% of international proved
reserves (93% of total proved reserves). The reserves audit for 2011 included a detailed review of 14 of our major fields and
covered approximately 90% of total proved reserves. The reserves audit for 2010 included a detailed review of 13 of our major
fields and covered approximately 88% of total proved reserves.
In connection with the 2012 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 Regulation S-X Rule 4-10(a) 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, oil and 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, 2012, 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.
The fields audited by NSAI are chosen in accordance with Company guidelines and result in the audit of a minimum of 80% of
our total proved reserves. The fields are chosen by the Vice President – Reserves and are reviewed by senior management and
the Audit Committee of our Board of Directors. Our practice is to select fields for audit based on size. This process results in
the audit of each field representing more than 1% of total proved reserves, as well as a selection of smaller fields. The Tamar
and Alen fields were first audited in 2010, and the Marcellus Shale field was first audited in 2011, as no reserves had been
recorded in prior years.
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, 2012, on a quantity basis, the NSAI field estimates
ranged from 26 MMBoe or 18% above to 1 MMBoe or 2% below 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, 2012 were, in the aggregate, approximately 48
MMBoe, or 4%.
Proved Undeveloped Reserves (PUDs) As of December 31, 2012, our PUDs totaled 159 MMBbls of crude oil, condensate
and NGLs and 3,382 Bcf of natural gas, for a total of 723 MMBoe.
PUDs Locations We have several significant ongoing development projects which are in various stages of completion. PUDs
are located as follows at December 31, 2012:
•
•
•
•
372 MMBoe in the Tamar field, offshore Israel, which will begin converting to proved developed at first production,
currently expected in second quarter 2013;
158 MMBoe in the DJ Basin, including Wattenberg, consisting of 958 horizontal Niobrara locations, which is equivalent
to less than three years of drilling based on current plans;
106 MMBoe in the Marcellus Shale, consisting of 290 horizontal locations, which is equivalent to less than three years
of drilling based on current plans;
74 MMBoe in Equatorial Guinea, 64% of which are in the Alba field with the remainder in the Alen field. The Alba
reserves, which will be recovered from existing wells with a sanctioned compression project, will be reclassified to
proved developed at start-up, currently expected in 2016. The Alen PUDs will be reclassified to proved developed at
start-up, currently expected in 2013;
18
•
•
the above fields represent 98% of total PUDs. The remaining 2% is associated with ongoing developments in various
areas scheduled in the next five years; and
PUDs include no material amounts which have remained undeveloped for five years or more.
Changes in PUDs Changes in PUDs that occurred during the year were due to:
•
•
•
•
•
•
•
•
recording of 135 MMBoe in the DJ Basin horizontal Niobrara program;
partially offset by negative revisions of 94 MMBoe in the DJ Basin due to our decision to terminate the legacy vertical
drilling program and focus capital and drilling rigs on the horizontal development of the Niobrara;
recording of 51 MMBoe in the Marcellus Shale as a result of an ongoing development program with expansion into the
wet gas area of the play;
recording of an additional 7 MMBoe at Tamar as a result of ongoing appraisal work, plus 1 MMBoe from other
international areas;
conversion of 82 MMBoe into proved developed reserves, primarily related to ongoing development in the DJ Basin
(19% of year-end 2011 PUDs converted) and Marcellus Shale (22% of year-end 2011 PUDs converted), the start-up of
the Galapagos project in the deepwater Gulf of Mexico, and a pipeline pressure-reduction project in Equatorial Guinea;
the sale of 3 MMBoe from our non-core asset divestiture program;
positive revisions of 10 MMBoe, primarily due to increased recovery assumptions in the Marcellus Shale as a result of
better than expected performance from existing wells; and
negative revisions of 7 MMBoe, primarily in the Marcellus Shale, due to changes in commodity prices.
Development Costs Costs incurred to advance the development of PUDs were approximately $1.8 billion in 2012, $1.4 billion
in 2011 (including $66 million non-cash costs related to an increase in our Aseng FPSO lease obligation), and $1.1 billion in
2010 (including $266 million non-cash costs related to an increase in our Aseng FPSO lease obligation). A significant portion
of costs incurred in 2012 related to our major development projects, horizontal Niobrara, Marcellus Shale, Alen and Tamar,
which will be converted to proved developed reserves in future years.
Estimated future development costs relating to the development of PUDs are projected to be approximately $1.8 billion in
2013, $1.5 billion in 2014, and $1.1 billion in 2015. Estimated future development costs include capital spending on major
development projects, some of which will take several years to complete. Proved undeveloped reserves related to major
development projects will be reclassified to proved developed reserves when production commences.
Drilling Plans All PUD drilling locations are scheduled to be drilled prior to the end of 2017. PUDs associated with projects
other than drilling (such as compression projects) are also expected to be converted to proved developed reserves prior to the
end of 2017. Initial production from these PUDs is expected to begin during the years 2013 - 2017.
For more information see the following:
•
•
•
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Proved Reserves for
a discussion of changes in proved reserves;
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 – Supplementary Oil and Gas Information (Unaudited) for
additional information regarding estimates of crude oil 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.
Other Reserves Information Since January 1, 2012, no crude oil or natural gas reserves information has been filed with, or
included in any report to, any federal authority or agency other than the SEC and the Energy Information Administration (EIA)
of the US Department of Energy (DOE). We file Form 23, including reserves and other information, with the EIA.
19
Sales Volumes, Price and Cost Data Sales volumes, price and cost data are as follows:
Sales Volumes
Average Sales Price
Production
Cost (1)
Crude Oil
&
Condensate
MBbl/d
Natural
Gas
MMcf/d
NGLs
MBbl/d
Crude Oil
&
Condensate
Per Bbl
Natural
Gas
Per Mcf
NGLs
Per
Bbl
Per BOE
Year Ended December 31, 2012
United States
Wattenberg
Other US
Total US
Equatorial Guinea
Alba Field (2)
Aseng Field
Total Equatorial Guinea
Mari-B Field (Israel)
China
Total Consolidated Operations
Equity Investee (3)
Total Continuing Operations
Year Ended December 31, 2011
United States
Wattenberg
Other US
Total US
Equatorial Guinea
Alba Field (2)
Aseng Field
Total Equatorial Guinea
Mari-B Field (Israel)
China
Total Consolidated Operations
Equity Investee (3)
Total Continuing Operations
Year Ended December 31, 2010
United States
Wattenberg
Other US
Total US (4)
Alba Field (Equatorial Guinea) (2)
Mari-B Field (Israel)
Ecuador (5)
China
Total Consolidated Operations
Equity Investee (3)
Total Continuing Operations
13
3
16
—
—
—
—
—
16
5
21
11
4
15
—
—
—
—
—
15
5
20
10
4
14
—
—
—
—
14
5
19
$
$
$
$
$
$
89.41
104.30
94.69
107.08
111.93
110.14
114.54
101.52
104.56
101.58
90.05
103.30
95.19
107.70
106.87
107.57
—
106.19
99.17
108.76
99.46
75.11
74.95
75.03
78.44
—
—
75.15
75.76
77.98
75.83
$
$
$
$
$
$
2.67
2.57
2.61
0.27
—
0.27
4.85
—
2.19
2.19
3.95
3.87
3.90
0.27
—
0.27
4.86
—
3.00
—
3.00
3.95
4.31
4.17
0.27
4.03
—
—
2.98
—
2.98
$
$ 35.50
34.92
35.36
—
—
—
—
—
35.36
69.14
$ 44.15
$
$ 49.45
45.40
48.35
—
—
—
—
—
48.35
72.71
$ 54.84
$ 43.15
36.23
41.21
—
—
—
—
41.21
53.68
$ 44.90
$
4.45
8.00
6.04
2.79
4.88
3.39
3.23
10.33
5.09
4.58
7.45
6.24
2.35
9.08
2.64
1.16
9.61
4.47
3.62
7.91
5.95
2.38
1.15
—
7.49
4.39
32
17
49
12
21
33
—
4
86
2
88
23
15
38
12
2
14
—
4
56
2
58
19
20
39
11
—
—
4
54
2
56
194
244
438
235
—
235
101
—
774
—
774
166
222
388
245
—
245
173
—
806
—
806
151
249
400
226
130
25
—
781
—
781
20
(1) Average production cost includes oil and gas operating costs and workover and repair expense and excludes production and ad valorem
taxes and transportation expenses.
(2) Natural gas is under contract for $0.25 per MMBtu to a methanol plant, an LPG plant and an LNG plant. Sales to these plants are based
on a Btu equivalent and then converted to a dry gas equivalent volume. The methanol and LPG plants are owned by affiliated entities
accounted for under the equity method of accounting. The volumes produced by the LPG plant are included in the crude oil information.
(3) Volumes represent sales of condensate and LPG from the LPG plant in Equatorial Guinea.
(4) Average crude oil sales prices reflect reductions of $1.32 per Bbl for 2010 from hedging activities. Average natural gas sales prices
reflect a decrease of $0.01 per Mcf for 2010 from hedging activities. This price reduction resulted from losses that were previously
deferred in AOCL. All hedge losses relating to US production had been reclassified to revenues by December 31, 2010.
(5)
Includes sales volumes through November 24, 2010. Our Block 3 PSC was terminated by the Ecuadorian government on November
25, 2010. Intercompany natural gas sales were eliminated for accounting purposes. Electricity sales are included in other revenues.
See Exit from Ecuador above.
Revenues from sales of crude oil, natural gas and NGLs have accounted for 90% or more of consolidated revenues for each of
the last three fiscal years.
At December 31, 2012, our operated properties accounted for approximately 72% 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, 2012
was as follows:
United States
Equatorial Guinea
Israel
North Sea
China
Total
Gross
Crude Oil Wells
Net
6,118.6
2.0
—
1.2
15.4
6,137.2
6,943
5
—
9
27
6,984
Gross
Natural Gas Wells
Net
5,083.7
6.7
3.7
1.1
0.6
5,095.8
6,718
18
9
9
1
6,755
Total
Gross
13,661
23
9
18
28
13,739
Net
11,202.3
8.7
3.7
2.3
16.0
11,233.0
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.
21
Developed and Undeveloped Acreage Developed and undeveloped acreage (including both leases and concessions) held at
December 31, 2012 was as follows:
(thousands of acres)
United States
Onshore (1)
Offshore
Total United States
International
Equatorial Guinea
Falkland Islands
Cameroon
Israel
Cyprus (2)
North Sea (3)
China
Sierra Leone
Nicaragua
India
Total International
Total
Developed Acreage
Net
Gross
Undeveloped Acreage
Gross
Net
1,808
96
1,904
285
—
—
124
—
20
7
—
—
—
436
2,340
1,186
41
1,227
119
—
—
58
—
4
4
—
—
—
185
1,412
2,207
500
2,707
180
9,921
1,084
1,333
852
131
—
1,380
1,855
694
17,430
20,137
1,512
373
1,885
80
3,472
542
581
596
25
—
414
1,855
347
7,912
9,797
(1) Developed acres includes approximately 464,000 gross (214,000 net) in the Marcellus Shale that are held by the production of others.
(2) A portion of the acreage has been assigned to a partner and the agreement is awaiting government approval.
(3) The North Sea includes acreage in the UK and the Netherlands.
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.
Future Acreage Expirations If production is not established or we take no other action to extend the terms of the leases,
licenses, or concessions, undeveloped acreage will expire over the next three years as follows:
(thousands of acres)
Onshore US (1)
Deepwater Gulf of Mexico
Equatorial Guinea
Israel (2)
Cyprus (3)
Cameroon (4)
Total
2013
Year Ended December 31,
2014
2015
Gross
Net
Gross
Net
Gross
Net
785
42
—
1,209
852
916
3,804
589
20
—
537
596
458
2,200
279
29
307
—
—
168
783
188
20
137
—
—
84
429
242
42
—
—
—
—
284
131
37
—
—
—
—
168
(1) Represents acreage that will expire if no further action is taken to extend. Approximately 35% of the acreage is located in core areas where
we currently expect to continue development activities and/or extend the lease terms.
(2) Represents acreage that will expire if no further action is taken to extend. We currently intend to extend the leases prior to expiration in
accordance with license terms.
22
(3) Represents acreage that will expire if no further action is taken to extend. We are currently planning to drill an appraisal well in 2013. The
result of this well will assist us in the evaluation of our acreage.
(4) The acreage in Cameroon is comprised of our Tilapia PSC and YoYo mining concession. Pursuant to the Tilapia PSC, our first exploration
period expires on July 6, 2013; however, we have the right to extend our acreage for two additional periods of two years each. Pursuant to
our YoYo mining concession, development must commence prior to December 2014; we are actively engaged in negotiations to extend the
term of the mining concession to 35 years.
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, 2012
United States
Equatorial Guinea
Cameroon
Israel
China
Total
Year Ended December 31, 2011
United States
Equatorial Guinea
Cameroon
Senegal/Guinea-Bissau
China
Total
Year Ended December 31, 2010
United States
Equatorial Guinea
Israel
North Sea
China
Total
8.1
—
—
—
—
8.1
9.6
—
—
—
—
9.6
4.8
—
—
—
—
4.8
2.3
—
0.5
—
—
2.8
3.7
—
0.5
0.3
—
4.5
1.9
—
—
—
—
1.9
10.4
—
0.5
—
—
10.9
13.3
—
0.5
0.3
—
14.1
6.7
—
—
—
—
6.7
457.5
2.3
—
3.2
1.7
464.7
641.2
0.5
—
—
2.9
644.6
510.6
2.0
1.0
0.6
2.3
516.5
—
—
—
—
—
—
4.0
—
—
—
—
4.0
1.0
—
—
—
—
1.0
457.5
2.3
—
3.2
1.7
464.7
645.2
0.5
—
—
2.9
648.6
511.6
2.0
1.0
0.6
2.3
517.5
Total
467.9
2.3
0.5
3.2
1.7
475.6
658.5
0.5
0.5
0.3
2.9
662.7
518.3
2.0
1.0
0.6
2.3
524.2
In addition to the wells drilled and completed in 2012 included in the table above, wells that were in the process of drilling or
completing at December 31, 2012 were as follows:
United States
Cameroon
Cyprus
Equatorial Guinea
Falkland Islands
Israel
Total
Exploratory (1)
Development
Total
Gross
Net
Gross
Net
Gross
Net
13
1
1
8
1
6
30
8.1
0.5
0.7
4.0
0.4
2.5
16.2
172
—
—
—
—
172
88.0
—
—
—
—
88.0
185
1
1
8
1
6
202
96.1
0.5
0.7
4.0
0.4
2.5
104.2
(1)
Includes exploratory wells drilled and suspended awaiting a sanctioned development plan or being evaluated to assess the economic
viability of the well.
See Item 8. Financial Statements and Supplementary Financial Data - Note 7. Capitalized Exploratory Well Costs for
additional information on suspended exploratory wells.
23
Oil Spill Response Preparedness We maintain membership in Clean Gulf Associates (CGA), a nonprofit association of
production and pipeline companies operating in the Gulf of Mexico. On behalf of its membership, CGA has contracted with
Helix Energy Solutions Group (HESG) for the provision of subsea intervention, containment, capture and shut-in capacity for
deepwater Gulf of Mexico exploration wells. The system, known as the Helix Fast Response System (HFRS), at full production
capacity, can contain well leaks up to 55 MBbl/d of oil, 70 MBbl/d of liquids and 95 MMcf/d of natural gas, at 10,000 pounds
per square inch (psi) in water depths to 10,000 feet. Resources also include a 15,000 psi-gauge intervention capping stack
designed to shut-in wells in water depths to 10,000 feet, including extremely high-pressure, deeper wells in the deepwater Gulf
of Mexico. We have entered into a separate utilization agreement with HESG which specifies the asset day rates should the
HFRS system be deployed.
Internationally, we maintain membership in Oil Spill Response Limited (OSRL). OSRL is an industry owned cooperative
which exists to ensure effective response to oil spills wherever they occur. OSRL is an industry leader in oil spill preparedness
and response services. We also maintain agreements internationally with Seacor. Seacor provides leased response equipment as
well as oil spill response services. Additionally, in Equatorial Guinea, we are members of the Oil and Gas Operators Emergency
Resource Allocation Group which shares equipment and resources in the event of a spill.
Domestic Marketing Activities Crude oil, natural gas, condensate and NGLs produced in the US are generally sold under short-
term and long-term contracts at market-based prices adjusted for location and quality. Crude oil and condensate are distributed
through pipelines and by trucks and rail cars to gatherers, transportation companies and refineries.
International Marketing Activities Our share of crude oil and condensate from the Aseng field is sold to Glencore Energy
UK Ltd (Glencore Energy) under a long-term sales contract at market rates and is transported by tanker. Natural gas from the
Alba field is sold under a long-term contract for $0.25 per MMBtu to a methanol plant, an LPG plant and an LNG plant. The
methanol and LPG plants are owned by affiliated entities accounted for under the equity method of accounting. 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,
and is transported by tanker.
In Israel, we sell natural gas from the Mari-B, Noa and Pinnacles fields, and have contracted to sell natural gas from the the
Tamar field, under long-term contracts. See Delivery Commitments below.
Our North Sea crude oil production is transported by tanker and sold on the spot market. In China, we sell crude oil into the
local market through pipelines under a long-term contract at market-based prices.
Delivery Commitments Some of our natural gas sales contracts specify the delivery of fixed and determinable quantities.
Mari-B GSPAs We currently sell natural gas from the Mari-B, Noa and Pinnacles fields to several customers, including Israel
Electric Corporation (IEC), under long-term Gas Sale and Purchase Agreements (Mari-B GSPAs). Due to end-of-field life
declines in production from these fields, we will not be able to meet all contractual delivery commitments under the Mari-B
GSPAs with reserves from these fields.
In January 2012, we issued force majeure notices to certain customers. The Mari-B GSPAs have customary liability cap
language that limits our financial exposure in the event we cannot fully deliver the contract quantities. Our liability is reflected
as a reduction in sales price for periods in which we are delivering partial contract quantities, or as a direct payment to the
customer in the event that no production is available for delivery (subject to force majeure considerations). To date, these
adjustments have totaled approximately $13 million, net. These sales price adjustments did not have a material impact on our
earnings or cash flows.
As of December 31, 2012, a total of 218 Bcf, gross, (102 Bcf, net) remained to be delivered under the Mari-B GSPAs. In the
fourth quarter of 2012, we and our Mari-B partners signed an agreement with IEC. The terms of the agreement provide for
delivery of up to 100,000 MMBtu/d, gross, (47,000 MMBtu/d, net) of natural gas under the first IEC sales contract, once the
Tamar field begins flowing, until the total contract quantity is fulfilled and, at the same time, termination of the second IEC
sales contract. We have executed similar agreements with most of the other Mari-B gas purchasers.
At December 31, 2012, our remaining Mari-B, Noa, and Pinnacles proved developed reserves totaled approximately 17 Bcf,
net, and will be used to satisfy our share of the Mari-B GSPAs on a pro-rata basis until the Tamar field begins producing. We
expect that approximately 30 Bcf, net, of our Tamar proved reserves will be used to satisfy our share of contract quantities that
remain to be delivered under the Mari-B GSPAs, as impacted by the recent agreements, when the fields cease producing. The
majority of the quantities remaining under the Mari-B GSPAs are expected to be delivered over a three year period with one
minor commitment extending over a 10-year period.
Tamar GSPAs As of December 31, 2012, we and our Tamar partners have entered into Gas Sale and Purchase Agreements
(Tamar GSPAs) with the IEC and numerous other Israeli purchasers, including independent power producers, cogeneration
facilities and industrial companies, for the sale of natural gas from the Tamar field. The Israeli government has approved the
Tamar GSPAs.
24
The Tamar GSPAs include the following:
•
•
•
sale of approximately 2.7 Tcf (approximately 1.0 Tcf net to us) of natural gas to IEC over an approximate 15-year
period. IEC has the option to increase this amount to 3.5 Tcf (approximately 1.3 net to us), under certain conditions;
sale of approximately 2.5 Tcf (approximately 0.9 Tcf net to us) of natural gas to additional customers. Most contracts
provide for the sale of natural gas over a 15 to 17 year period. Some of the contracts provide for increase or reduction
in total quantities and some are interruptible during certain contract periods; and
sales prices based on an initial base price subject to price indexation over the life of the contract and with a floor. The
IEC contract also provides for price reopeners in the eighth and eleventh years with limits on the increase/decrease
from the contractual price.
Under the Tamar GSPAs, 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 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 (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.
At December 31, 2012, we have recorded 2.2 Tcf, net, of PUD reserves for the Tamar field. We expect to begin reclassifying
these PUD reserves to proved developed at first production, currently expected in second quarter 2013. See International -
Eastern Mediterranean (Israel and Cyprus) - Tamar Natural Gas Project.
Significant Purchaser Glencore Energy was the largest single non-affiliated purchaser of 2012 production and purchased our
share of crude oil and condensate production from the Alba and Aseng fields in Equatorial Guinea. Sales to Glencore Energy
accounted for 31% of 2012 total oil, gas and NGL sales, or 39% of 2012 crude oil sales. Shell Trading (US) Company and Shell
International Trading and Shipping Limited (collectively, Shell) purchased crude oil and condensate domestically from the
deepwater Gulf of Mexico and the Wattenberg area and internationally from the North Sea. Sales to Shell accounted for 14% of
2012 total oil, gas and NGL sales, or 17% of crude oil sales. No other single non-affiliated purchaser accounted for 10% or
more of crude oil and natural gas sales in 2012. We 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 were volatile in 2012 and prices for crude oil and natural gas are affected by a variety
of factors beyond our control. We have used derivative instruments, and expect to do so in the future, 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. As a result of hedging, near-term cash flow volatility is reduced, which allows us to plan our financial
commitments and support our capital investment programs.
Our practice is to hedge up to 50% of our forecasted domestic natural gas production and up to 50% of our total forecasted
domestic and international crude oil production, for the current year plus two additional calendar years. We strive to maintain
strong governance of our hedging program, including oversight by our Board of Directors. For additional information, see Item
1A. Risk Factors – Commodity and interest rate hedging transactions may limit our potential gains and We are exposed to
counterparty credit risk as a result of our receivables, hedging transactions, and cash investments, Item 7A. Quantitative and
Qualitative Disclosures About Market Risk, and Item 8. Financial Statements and Supplementary Data – Note 10. Derivative
Instruments and Hedging Activities.
Regulations
Government Regulation Exploration for, and production and marketing of, crude oil and natural gas are extensively regulated
at the federal, state, and local levels in the US, and internationally. Crude oil and natural gas 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 and frequently increase the regulatory requirements on oil and gas companies.
Our ability to economically produce and sell crude oil and natural gas 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 and regulations that require extensive efforts to ensure compliance and incremental cost
to comply, and that carry substantial penalties for failure to comply. These laws, regulations and orders may restrict the rate of
crude oil and natural gas 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.
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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:
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the Ministry of Mines, Industry and Energy 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 and Water Resources which regulates both 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;
the Ministry of Commerce, Industry, and Tourism which regulates our exploration and development activities offshore
Cyprus;
the Department of Energy and Climate Change which regulates our exploration and development activities in the UK
sector of the North Sea;
various agencies in China which, under such laws as the Provisional Regulations on Administration and Management of
the Abandonment of Offshore Oil and Gas Producing Facilities enacted in 2010, regulate our development and
production activities offshore China;
the Petroleum Directorate which regulates our exploration activities offshore Sierra Leone; and
the Department of Mineral Resources which regulates our exploration activities offshore the Falkland Islands.
Examples of other laws affecting our international operations are the Israeli Petroleum Profits Taxation Law, 2011, which
imposes additional income tax on oil and gas production, and the UK Finance Bill 2011, which increased the rate of the
Supplementary Charge levied on oil and gas income. Under the Israeli Petroleum Profits Taxation Law, 2011, the depletion
allowance was abolished, and a levy at an initial rate of 20% was imposed on profits from oil and gas. The levy gradually rises
to 50%, depending on the levy coefficient (the R-Factor). The R-Factor refers to the percentage of the amount invested in the
exploration, development and establishment of the project, so that the 20% rate is imposed only after a recovery of 150% of the
amount invested (R-Factor of 1.5) and scales linearly up to a maximum of 50% after a recovery of 230% of the amount
invested (R-Factor of 2.3). The rate of royalties paid to the State of Israel remained unchanged. Also affecting our operations in
Israel is the Law for Change in the Tax Burden (Amendments to Legislation), 2011 (the 2011 Tax Act). As from 2012, the 2011
Tax Act eliminates, inter alia, a previously enacted progressive reduction in the rate of corporate tax rate, and increases the
corporate tax rate to 25%.
Examples of US federal agencies with regulatory authority over our exploration for, and production and sale of, crude oil and
natural gas include:
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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, particularly in the Rocky Mountains and deepwater 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, as amended, the
Resource Conservation and Recovery Act, as amended, 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, which under the Endangered Species Act has authority over activities that may result in
the take of an endangered 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 and natural gas we produce onshore and from the deepwater
Gulf of Mexico; and
the Department of Transportation (DOT), which has certain authority over the transportation of products, equipment and
personnel necessary to our onshore US and deepwater 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.
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Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat,
wetlands, migratory birds, and 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 oil and natural gas exploration
activities. 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.
On May 17, 2010, the BLM issued a revised oil and gas leasing policy that requires, among other things, a more detailed
environmental review prior to leasing oil and natural gas rights, increased public engagement in the development of master leasing
and development plans prior to leasing areas where intensive new oil and gas development is anticipated, and a comprehensive
parcel review process.
The EPA has issued the Final Mandatory Reporting of Greenhouse Gases Rule, which requires many suppliers of fossil fuels or
industrial chemicals, manufacturers of vehicles and engines, and other facilities that emit 25,000 metric tons or more of carbon
dioxide equivalent per year to begin collecting greenhouse gas (GHG) emissions data, beginning in 2012 for 2011 emissions,
under a new reporting system that went into effect on January 1, 2010. The first annual report was due September 30, 2011. In
November 2010, the EPA issued final regulations requiring the annual reporting of GHG emissions from qualifying facilities in
the upstream oil and natural gas sector, including onshore production (Subpart W). Substantially all of our onshore US
properties are subject to the Subpart W reporting requirements.
On April 18, 2012, the EPA issued regulations under the New Source Performance Standards (NSPS) and National Emission
Standards for Hazardous Air Pollutants. The new rules are related to emissions associated with crude oil and natural gas
production, including natural gas wells that are hydraulically fractured. The required technologies and processes, while
reducing emissions, will also enable companies to collect additional natural gas that can be sold. The EPA's final standards also
address emissions from storage tanks and other equipment. The final rules establish a phase-in period that will ensure that
manufacturers have time to make and broadly distribute the required emissions reduction technology. During the first phase,
until January 2015, owners and operators must either flare their emissions or use emissions reduction technology called “green
completions,” technologies that are already widely deployed at wells. In 2015, all newly fractured wells will be required to use
green completions. The EPA's final rules have minimal impact on our business. The reduction of greenhouse gas emissions
(GHG) is already one of our priorities and we have been working to improve our methods to reduce GHGs through operational
and business practices. We use green completions or flaring on a number of our wells to comply with Colorado Oil and Gas
Conservation Commission (COGCC) rules. Additionally we've undertaken emission reduction projects such as our US Vapor
Recovery Unit (VRU) program, where we have installed VRUs to capture gas that would otherwise be flared on a substantial
number of our tank batteries.
Most of the states within which we operate have separate agencies with authority to regulate related operational and
environmental matters.
Colorado Examples of such regulation on the operational side include the Greater Wattenberg Area Special Well Location
Rule 318A (Rule 318A), which was adopted by the COGCC to address oil and gas well drilling, production, commingling and
spacing in Wattenberg. On August 9, 2011, the COGCC approved amendments to Rule 318A. The amendments, which became
effective on October 1, 2011, remove the limit on the number of wells which can produce from a particular formation, allowing
wellbore spacing units and permitting wells to cross section lines. The amendments also address areas such as infill drilling,
water sampling and waste management plans.
In February 2013, the COGCC is expected to approve and implement new setback rules for oil and gas wells and production
facilities located in close proximity to occupied buildings. If the new setback rules are approved, the current COGCC setback
distances of 150 feet in rural areas and 350 feet in high density urban areas will be increased to a uniform 500 feet statewide
setback from occupied buildings and a uniform 1,000 feet statewide setback from high occupancy building units. The new
setback rules would also require operators to utilize increased mitigation measures to limit potential drilling impacts to surface
owners and the owners of occupied building units. The new rules would also 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 expanded outreach and communication efforts by an operator.
The COGCC also approved two new rules making Colorado the first state to require sampling of groundwater for hydrocarbons
and other indicator compounds both before and after drilling. The new statewide rule requires sampling of up to four water
wells within a half mile radius of a new oil and gas well before drilling, between six and 12 months after completion, and
between five and six years after completion. The revised rule for the GWA requires operators to sample only one water well per
quarter governmental section before drilling and between six to 12 months after completion.
On the environmental side, Colorado Regulation Seven and requirements for storm water management plans were adopted by
the Colorado Department of Environmental Quality, under delegation from the EPA, to regulate air emissions, water protection
and waste handling and disposal relating to our oil and gas exploration and production.
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Pennsylvania On February 14, 2012, Governor Tom Corbett of Pennsylvania signed into law what is known as Act 13 of 2012
(Act 13). Act 13 represents the first comprehensive legislation regarding the development of the Marcellus Shale in
Pennsylvania. Act 13, among other things, enacted stronger environmental standards and established impact fees, which in
2012 equaled $50,000 for each horizontal Marcellus Shale well. Act 13 also increased the notice distance of unconventional
well permit applications from 1,000 feet to 3,000 feet, and extended the setback distance for unconventional wells from 200
feet to 500 feet. The statute also increased the distance and duration of presumed liability for water pollution to 2,500 feet from
a well site and twelve months after well completion, drilling, stimulation, or alteration. In addition, Act 13 imposed spill
prevention requirements applicable to well site construction, wastewater transportation, and gathering lines. These requirements
may result in increased costs and lower rates of return for our Marcellus Shale development project.
In March 2012, seven municipalities filed suit against Act 13's statewide zoning provisions, claiming that Act 13 violated the
state constitution. On July 26, 2012, the Pennsylvania Commonwealth Court declared the statewide zoning provisions in Act
13 unconstitutional, null, void and unenforceable. The Court also struck down the provision of the law that required the
Pennsylvania Department of Environmental Protection to grant waivers to the setback requirements in Pennsylvania's Oil and
Gas Act. This decision was appealed to the Pennsylvania Supreme Court and arguments were presented on October 18, 2012.
The decision from the Supreme Court is still pending, but a ruling upholding the lower court's decision could make it more
difficult to develop our Marcellus acreage in some municipalities within Pennsylvania.
NETL Study The US Department of Energy's National Energy Technology Laboratory (NETL) is conducting a comprehensive
assessment of the environmental effects of shale gas production at two industry-provided Marcellus Shale test sites in
southwestern Pennsylvania. Goals include:
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documentation of environmental changes that are coincident with shale gas production;
development of technology or management practices that mitigate undesigned environmental changes; and
development of monitoring technologies to (1) assess the impact of shale gas production on air quality and (2)
determine if zonal isolation between producing formations and drinking water aquifers is maintained after hydraulic
fracturing.
We will monitor the results of the NETL study in order to assess any potential impact on our onshore US development
programs.
In December 2011, the West Virginia legislature passed, and the governor signed, the Natural Gas Horizontal Wells Control Act,
which, among other things, provides for increased well permit fees, well location restrictions, well site safety, public notice
requirements for municipalities, and regulations regarding water use and wastewater handling.
Some of the counties and municipalities within which we operate have adopted regulations or ordinances that impose additional
restrictions on our oil and gas exploration and production. An example is Garfield County, Colorado, which provides local land
and road use restrictions affecting our Piceance Basin operations and requires us to post bonds to secure any restoration obligations.
Israeli Interministerial Committee In 2011, the Interministerial Committee to Examine Government Policy Regarding the
Natural Gas Industry in Israel (the Committee) was charged with the task of proposing a government policy for developing the
natural gas economy. Objectives include the following:
ensuring energy security in the economy;
providing a framework for substantial resource exports;
designating a certain percentage of production from each field for domestic natural gas demand;
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• maintaining competition in the different sectors of the local economy;
• maximizing economic and political benefits; and
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leveraging environmental advantages with respect to the use of natural gas.
The Committee was also asked to examine, among other items, the desired policy to maintain reserves to supply local demand
and export of natural gas. In September 2012, the Committee issued its final recommendations. In its report, the Committee
stated that permitting export of natural gas does not prevent, but rather promotes the ensuring of the needs of domestic users
and works to encourage development of natural gas-based domestic industry. The recommendations included, among others,
the following points:
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as a rule, all reservoirs should be charged with supplying a certain percentage of natural gas to the local economy, with
minimum requirements based on reservoir size (minimum of 25%-50%). The minimum supply obligations will not
apply for reservoirs under a certain size (25 BCM) but the reservoirs will be required to be connected to the domestic
market. The recommendations allow for a lease in a developed reservoir to exchange its export quota against an
"obligation to supply to the domestic market" which applies to any other leaseholder which submitted a development
plan so long as approval therefor is given by the Petroleum Commissioner in the Ministry of Energy and Water
Resources and by the Antitrust Authority;
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a determination that the quantity of natural gas that should be guaranteed in favor of the local economy should be 450
BCM and that the quantity should be updated in five years;
the export of natural gas should be permitted as long as the quantity from all reservoirs does not exceed 500 BCM,
which amount may be reassessed;
regulatory approval required for export, with export licenses eligible for periods up to 25 years;
there should be an absolute preference for the export of natural gas from a facility in an area under Israeli control,
including Israel's exclusive economic zone, although further study of various export means (such as export from a
foreign area governed by bilateral agreement) and statutory feasibility is necessary; and
steps should be taken to increase competition in the natural gas market.
We are participating in the process and monitoring the impact of the Committee's recommendations. However, at this time, we
cannot predict the ultimate outcome of the Committee's recommendations or the possible impact any resulting laws or
regulations could have on our business. Certain changes in Israel's market, fiscal, and/or regulatory regimes occurring as a
result of the Committee's recommendations could delay or reduce the profitability of our Tamar and/or Leviathan development
projects and render future exploration and/or development projects uneconomic.
Impact of Dodd-Frank Act Derivatives Regulation The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-
Frank Act), which was passed by Congress and signed into law in July 2010, contains significant derivatives regulation,
including requirements that certain transactions be cleared on exchanges and that collateral (commonly referred to as “margin”)
be posted for such transactions. The Dodd-Frank Act provides for a potential exception from these clearing and collateral
requirements for commercial end-users, such as us, and it includes a number of defined terms used in determining how this
exception applies to particular derivative transactions and the parties to those transactions. As required by the Dodd-Frank Act,
the Commodities Futures and Trading Commission (CFTC) has promulgated numerous rules to define these terms.
We have been evaluating the provisions of the CFTC's final rules and assessing their impact on our commodity hedging
program. At this time, we believe that we will be able to satisfy the requirements for the commercial end-user clearing
exception and continue to engage in transactions which hedge commercial risk and are free of mandated clearing requirements.
It is possible that the CFTC, in conjunction with prudential regulators, may mandate that financial counterparties entering into
swap transactions with end-users must do so with credit support agreements in place, which could result in negotiated credit
thresholds above which an end-user must post collateral. If this should occur, we intend to manage our credit relationships to
minimize collateral requirements.
The CFTC's final rules will also have an impact on our hedging counterparties. For example, our bank counterparties will be
required to post collateral and assume compliance burdens resulting in additional costs. We expect that much of the increased
costs will be passed on to us, thereby decreasing the relative effectiveness of our hedges and our profitability. To the extent we
incur increased costs or are required to post collateral in periods of rising commodity prices, there could be a corresponding
decrease in amounts available for our capital investment program. See Item 1A. Risk Factors - Derivatives regulation included
in current or proposed financial legislation and rulemaking could impede our ability to manage business and financial risks by
restricting our use of derivative instruments as hedges against fluctuating commodity prices and interest rates.
Impact of Dodd-Frank Act Section 1504 Section 1504 of the Dodd-Frank Act required the SEC to issue rules requiring
resource extraction issuers to include in an annual report information relating to any payment made by the issuer, a subsidiary
of the issuer, or an entity under the control of the issuer, to a foreign government or the federal government for the purpose of
the commercial development of oil, natural gas, or minerals. On August 22, 2012, the SEC issued a final rule, Disclosure of
Payments by Resource Extraction Issuers (Rule). The Rule requires resource extraction issuers, such as us, to provide
information about the type and total amount of payments made for each project related to the commercial development of oil,
natural gas, or minerals, and the type and total amount of payments made to each government. The first report is due May 30,
2014.
In October 2012, the U.S. Chamber of Commerce, American Petroleum Institute, Independent Petroleum Association of
America, and National Foreign Trade Council filed a lawsuit against the SEC in the U.S. Court of Appeals for the District of
Columbia Circuit. The petitioners argued that the Rule is “arbitrary and capricious” within the meaning of the Administrative
Procedure Act and that the Rule and statute violate the First Amendment. Briefs have been submitted. Oral arguments are not
yet scheduled.
See Item 1A. Risk Factors - Disclosure of certain operating information as required by Section 1504 of the Dodd-Frank Act
could have a negative impact on our operations.
See also Item 1A. Risk Factors - Our operations may be adversely affected by changes in the fiscal regimes and government
policies and regulation of oil and gas development in the countries in which we operate for a discussion of the American
Taxpayer Relief Act of 2012.
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Environmental Matters As a developer, owner and operator of crude oil and natural gas properties, we are subject to various
federal, state, local and foreign country laws and regulations relating to the discharge of materials into, and the protection of,
the environment. We must 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 waste products, water and air pollution control procedures, facility siting and construction, and the
remediation of petroleum-product contamination. 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 prior owners or operators in accordance with
current laws or otherwise, to suspend or cease operations in contaminated areas, or to perform remedial well plugging
operations or cleanups to prevent future contamination. The EPA and various state agencies have limited the disposal options
for hazardous and non-hazardous wastes. 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. Furthermore, certain wastes generated by our crude oil and
natural gas operations that are currently exempt from treatment as hazardous wastes may in the future be designated as
hazardous wastes and, therefore, be subject to considerably more rigorous and costly operating and disposal requirements. See
Item 1A. Risk Factors – We are subject to increasing governmental regulations and environmental requirements that may cause
us to incur substantial incremental costs.
Federal and state occupational safety and health laws require us to organize 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.
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 we have, to date, expended material amounts in connection with such activities or 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.
Hydraulic Fracturing
Concerns The practice of hydraulic fracturing, especially the hydraulic fracturing processes associated with drilling in shale
formations, is the subject of significant focus among some environmentalists, regulators and the general public. Concerns over
potential hazards associated with the use of hydraulic fracturing and its impact on the environment have been raised at all
levels, including federal, state and local, as well as internationally. There have been claims that hydraulic fracturing may
contaminate groundwater, reduce air quality or cause earthquakes. Hydraulic fracturing requires the use and disposal of water,
and public concern has been growing over its possible effects on drinking water supplies, as well as the adequacy of supply.
Our Operations Hydraulic fracturing techniques have been used by the industry for many years, and, currently, more than
90% of all oil and natural gas wells drilled in the US employ hydraulic fracturing. We strive to adopt best practices and industry
standards and comply 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 aquifers.
We strive to procure non-hydrologic water (water that is not connected to a natural surface stream); approximately 80% of our
water is from non-tributary sources, such as deep ground water. In the DJ Basin, we are in the process of securing additional
water rights in support of our drilling program and implementing a pilot water recycling program. In the Marcellus Shale, our
joint development agreement with CONSOL provides us with access to water resources which we believe will be adequate to
execute our development program, and we engage in recycling efforts. We believe that these processes help ensure that
hydraulic fracturing does not pose a meaningful risk to water supplies.
Potential Rulemaking Although hydraulic fracturing is regulated primarily at the state level, governments and agencies at all
levels from federal to municipal are conducting studies and considering regulations. For example, in 2011, the US Secretary of
Energy formed the Shale Gas Production Subcommittee (Subcommittee), a subcommittee of the Secretary of Energy Advisory
Board. The Subcommittee was charged with making recommendations to improve the safety and environmental performance of
hydraulic fracturing. On August 18, 2011, the Subcommittee issued its Ninety Day Report (Report), which focused exclusively
on the production of natural gas (and some liquid hydrocarbons) from shale formations with hydraulic fracturing stimulation in
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either vertical or horizontal wells. The Subcommittee identified four primary areas of concern including possible water
pollution, air pollution, disruption of the community during production, and potential for adverse impact on communities and
ecosystems. The Subcommittee also set forth a list of recommendations addressing, among other areas, communications, air
quality, protection of water supply and quality, disclosure of fracturing fluid composition, reduction of diesel fuel use,
continuous development of best practices, and federal sponsorship of research and development with respect to unconventional
gas. The Subcommittee issued its Final Report in November 2011 which recommends implementation of the Subcommittee’s
recommendations by federal and state agencies. We continue to monitor the impact the Subcommittee’s recommendations, and
any resulting rule-making activities evolving at federal and state levels, could have on our exploration and development
activities in shale formations.
During 2012, the BLM proposed regulations governing hydraulic fracturing on federal lands. The regulations would require:
(1) public disclosure of chemicals used in hydraulic fracturing operations; (2) assurances on well-bore integrity to verify that
fluids used in wells during fracturing operations are not escaping; and (3) confirmation of a water management plan in place for
handling fracturing fluids that flow back to the surface. On January 21, 2013, the BLM announced that it was withdrawing its
proposed regulations and would reissue a new set of proposed regulations regarding hydraulic fracturing later in 2013.
During 2012, the EPA proposed new guidelines under the Safe Drinking Water Act regarding the issuance of permits for the use
of diesel fuel as a component in hydraulic fracturing activities. The draft guidance outlines for EPA permit writers, where EPA
is the permitting authority, requirements for diesel fuels used for hydraulic fracturing wells, technical recommendations for
permitting those wells, and a description of diesel fuels for EPA underground injection control permitting.
The EPA is currently studying the potential impacts of hydraulic fracturing on drinking water resources. Results are expected to
be released in a draft for public and peer review in 2014. In addition, the EPA’s recently-issued proposed rules subjecting oil
and gas operations to regulation under the New Source Performance Standards will be applicable to newly drilled and fractured
wells as well as existing wells that are refractured.
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. OSHA is working with industry and other government agencies
to review existing regulations for applicability to hydraulic fracturing.
In 2012, the City of Longmont, Colorado voted to ban hydraulic fracturing activities within city limits. Subsequently, the State
of Colorado, through the COGCC, sued the City of Longmont in Boulder County District Court to set aside a city ordinance
that promulgated stricter oil and gas rules than the COGCC Rules asserting that portions of these rules are preempted by State
statutes and COGCC rules. The Colorado Oil and Gas Association (COGA) moved to intervene in this action and intervention
was granted. COGA also separately sued the City of Longmont claiming that the resolution is a taking of the mineral property
rights and an improper regulatory impairment of such rights, that it is effectively an illegal ban on drilling, and otherwise
asserting that the ban must be set aside since it conflicts with Colorado state law allowing the practice.
We continue to monitor new and proposed legislation and regulations to assess the potential impact on our operations. We are
currently evaluating the possible impact any proposed rules, such as those described above, could have on our business. Any
additional federal, state or local restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business
could result in substantial incremental operating, capital and compliance costs as well as delay our ability to develop oil and gas
reserves.
Public Disclosure Several states have issued regulations requiring disclosure of certain information regarding the components
used in the hydraulic-fracturing process. In 2011, the Texas Railroad Commission (RRC) adopted the Hydraulic Fracturing
Chemical Disclosure rule, under which companies are required to provide a listing of chemical ingredients used to
hydraulically fracture wells that are permitted by the RRC on or after February 1, 2012 on a public national chemical disclosure
registry, FracFocus.org, operated jointly by the Interstate Oil & Gas Compact Commission and the Ground Water Protection
Council. In December 2011, the COGCC adopted hydraulic fracturing fluid ingredient regulations requiring disclosure of all
chemicals and establishing ways to protect proprietary information. The regulations allow disclosure through the FracFocus
web site. The State of Wyoming also requires disclosure of the types and amounts of chemicals. In 2012, through legislation
known as Act 13, Pennsylvania established a requirement that operators submit information regarding hydraulic fracturing
chemicals to FracFocus.org. Other states have proposed, or are considering, similar regulations which require specific
disclosures by operators and/or outline requirements for construction and operation of wells and monitoring of well activity. We
are currently providing disclosure information on FracFocus.org for all onshore US areas in which we operate.
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Additional Information See:
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Items 1. and 2. Business and Properties – Regulations;
Item 1A. Risk Factors – Federal or state hydraulic fracturing legislation could increase our costs or restrict our access
to oil and gas reserves;
Item 1A. Risk Factors – Our ability to produce crude oil and natural gas 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;
Item 1A. Risk Factors – We face various risks associated with the trend toward increased anti-development activity; and
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and
Capital Resources – Risk and Insurance Program.
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 continuous effort.
We begin by leasing acreage (or deepwater lease blocks) from individuals, other operators or the federal government. It may
take years for us to assemble enough 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 locate a drilling rig with the specifications for the depth and pressure situation in which we will drill.
For example, several years ago, we wanted to leverage our expertise in the Wattenberg area to open a new opportunity in
Northern Colorado. We began acquiring acreage spanning an area from the edge of the GWA to the Wyoming border. It took
over two years to assemble enough acreage through acquisition and leasing to have a significant enough acreage position to
warrant data collection. Once the acreage position had been established, we conducted an extensive 3D seismic program and
obtained other data as well, which our exploration staff analyzed and used to plan an initial drilling program.
After drilling an exploratory well, we must integrate data, such as core samples and well logs, obtained from the drilling
process with our seismic and other data to determine if we have discovered hydrocarbons.
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, and make an investment decision. Appraisal or
development drilling requires additional time to contract for an appropriate drilling rig, and obtain pipe, other equipment, and
supplies. Due to the current high level of drilling activity, drilling rigs and hydraulic fracturing crews are in high demand, and
there could be substantial delays as we wait for rigs or crews to become available.
In Northern Colorado, our data collection efforts resulted in a successful initial drilling program. Due to the success of our first
wells, we have continued the Northern Colorado drilling program and, in 2012, we drilled 25 development wells.
We strive to maintain an appropriate inventory of onshore and offshore exploration prospects suitable to our experience as an
operator, financial resources, and current development timeline.
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 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 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 – We face
significant competition and many of our competitors have resources in excess of our available resources.
Geographical Data
We have operations throughout the world and manage our operations by country. Information is grouped into four components
that are all primarily in the business of crude oil, natural gas and NGL exploration, development and production: United States,
West Africa, Eastern Mediterranean, and Other International and Corporate. See Item 8. Financial Statements and
Supplementary Data – Note 17. Segment Information.
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Employees
Our total number of employees increased 17%, from 1,876 at December 31, 2011 to 2,190 at December 31, 2012, in support of
our major development and exploration projects. The 2012 year-end employee count includes 203 foreign nationals working as
employees in Israel, the UK, Equatorial Guinea, Cyprus, and Cameroon. We regularly use independent contractors and
consultants to perform various field and other services.
Offices
Our principal corporate office is located at 100 Glenborough Drive, Suite 100, Houston, Texas 77067-3610. We maintain
additional offices in Ardmore, Oklahoma; Denver, Colorado; Greeley, Colorado; and Canonsburg, Pennsylvania; and in China,
Cameroon, Equatorial Guinea, Israel, Cyprus, Nicaragua, and the UK.
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.
Butler vs. Powers On September 7, 2011, an intermediate appellate court (Superior Court) in Pennsylvania issued an opinion
in Butler v. Powers regarding the interpretation of a deed. As a result, traditional views of how ownership of shale gas is
determined in that state have been called into question. The issue raised by the case is whether shale gas is different from other
natural gas and should be considered part of mineral rights, rather than oil and gas rights, because shale gas is contained inside
unconventional shale rock. An appeal of the decision was subsequently filed with the Pennsylvania Supreme Court, which
decided to hear the appeal. Written and oral arguments in the case have been presented and the parties are awaiting the decision
of the Court.
At this time, no case law or interpretation of existing law has changed, nor has there been an indication that either the Superior
Court or the Pennsylvania Supreme Court will seek to change existing law. Based upon our initial review, we believe that any
adverse decision in the pending case would have minimal adverse impact upon the assets acquired from CONSOL and our
Marcellus Shale joint venture operations.
Title Defects Subsequent to a lease or fee interest acquisition, such as our Marcellus Shale acquisition in 2011, 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. We continue to
examine some of our Marcellus Shale leases and fee interests for potential title defects. Options to address uncured title defects
include a reduction in the remaining amount of the CONSOL Carried Cost Obligation, an indemnity agreement, or the transfer
of additional interests.
Conflicts with Surface Rights Mineral rights are property rights that confer to the holder 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 to prevent companies from using their
land surface to drill horizontal wells to explore for or produce natural gas 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.
Risk Management
The oil and gas business is subject to many significant risks, including operational, strategic, financial and compliance/
regulatory risks. We strive to maintain a proactive enterprise risk management (ERM) process to plan, organize, and control our
activities in a manner which is intended to minimize the effects of risk on our capital, cash flows and earnings. ERM expands
our process to include risks associated with accidental losses, as well as financial, strategic, operational, regulatory, political,
and other risks.
Our ERM process is designed to operate in an annual cycle, integrated with our long range plans, and supportive of our capital
structure planning. Elements include, among others, a robust global compliance program, credit risk management, a commodity
hedging program to reduce the impacts of commodity price volatility, an insurance program to protect against disruptions in our
cash flows, and cash flow at risk (CFAR) analysis. We benchmark our program against our peers and other global
organizations. See Item 1A. Risk Factors for a discussion of specific risks we face in our business.
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Available Information
Our website address is www.nobleenergyinc.com. Available on this website under “Investors – Investors Menu – 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, 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 “About Us – Corporate Governance”, 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. On
October 25, 2011 our Board approved and adopted a revised Code of Business Conduct and Ethics. Copies of the revised Code
of Business Conduct and Ethics, and the Code of Ethics for Chief Executive and Senior Financial Officers (the Codes) are
posted on our website under the “Corporate Governance” 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, 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.
Crude oil, natural gas, and NGL prices are volatile and a reduction in these prices could adversely affect our results of
operations, our liquidity, and the price of our common stock.
Our revenues, operating results and future rate of growth depend highly upon the prices we receive for our crude oil, natural
gas, and NGL production. Historically, the markets for crude oil, natural gas, and NGLs have been volatile and are likely to
continue to be volatile in the future. For example, high and low daily average settlement prices for prompt month contracts for
crude oil and natural gas during 2012 were as follows:
Year Ended December 31, 2012
NYMEX
Crude Oil - WTI (Per Bbl)
Natural Gas - HH (Per MMBtu)
Brent
Crude Oil (Per Bbl)
Daily Average Settlement Price
for Prompt Month Contracts
High
Low
$
109.77
3.90
$
126.22
77.69
1.91
89.23
Prices for our NGL production are determined at two primary market centers, Conway and Mt. Belvieu. For the year ended
December 31, 2012, our consolidated net realized NGL prices were approximately 37% of consolidated net realized crude oil
prices and tended to track the volatility of NYMEX WTI.
The markets and prices for crude oil, natural gas, and NGLs depend on factors beyond our control, factors including, among
others:
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economic factors impacting global gross domestic product growth rates;
global demand for crude oil, natural gas and NGLs;
global factors impacting supply quantities of crude oil, natural gas and NGLs;
OPEC spare capacity relative to global crude oil supply;
further application of horizontal drilling techniques which could increase production and significantly impact both
domestic and global supplies of crude oil and natural gas;
ability to develop natural gas in shale or crude oil in tight formations relatively inexpensively which could increase the
supply of natural gas or crude oil;
the potential expansion of the global LNG market, including potential exports from the US;
actions taken by foreign hydrocarbon-producing nations;
political conditions and events (including instability or armed conflict) in hydrocarbon-producing regions;
the existence of government imposed price and or product subsidies;
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• weather conditions;
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the price and availability of alternative fuels, including coal, solar, wind, nuclear energy and biofuels;
the long-term impact on the crude oil market of the use of natural gas as an alternative fuel for road transportation;
the availability of pipeline capacity and infrastructure;
the availability of crude oil transportation and refining capacity;
demand for electricity as well as natural gas used as fuel for electricity generation;
impact of conservation efforts on the ability to access government-owned and other lands for exploration and
production activities; and
domestic and foreign governmental regulations and taxes.
•
Declines in commodity prices or lack of natural gas storage may have the following effects on our business:
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reduction of our revenues, operating income and cash flows;
curtailment or shut-in of our natural gas production due to lack of transportation or storage capacity;
reduction in the amount of crude oil, natural gas, and NGLs that we can produce economically;
cause certain properties in our portfolio to become economically unviable;
cause us to delay or postpone some of our capital projects, including our horizontal Niobrara and Marcellus Shale,
deepwater Gulf of Mexico, or international development projects;
cause significant reductions in our capital investment programs, resulting in a reduced ability to develop our reserves;
limit our financial condition, liquidity, and/or ability to finance planned capital expenditures and operations; and
limit our access to sources of capital, such as equity and long-term debt.
In addition, lower commodity prices, including declines in the forward commodity price curves, may result in the following:
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asset impairment charges resulting from reductions in the carrying values of our oil and gas properties at the date of
assessment, such as occurred in 2012, 2011, and 2010;
additional counterparty credit risk exposure on commodity hedges; or
a reduction in the carrying value of goodwill.
Failure to effectively execute our major development projects could result in significant delays and/or cost over-runs,
damage to our reputation, limitation of our growth and negative impact on our operating results, liquidity and financial
position.
We currently have an extensive inventory of major development projects in various stages of development. Gunflint, Big Bend,
Leviathan, Cyprus, Carla and Diega are being appraised and, as such, not yet sanctioned, and it will take several years before
first production is achieved. Some projects, such as crude oil and natural gas projects offshore West Africa and the Eastern
Mediterranean, entail significant technical and other complexity, including extensive subsea tiebacks to an FPSO or production
platform, pressure maintenance systems, gas re-injection systems, onshore receiving terminals, or other specialized
infrastructure. Our Leviathan project also includes potential LNG infrastructure. In addition, we have expanded our horizontal
drilling programs in the Niobrara formation and Marcellus Shale.
This level of development activity requires significant effort from our management and technical personnel and places
additional requirements on our financial resources and internal financial controls. In addition, we have increased dependency
on third-party technology and service providers and other supply chain participants for these complex projects. We may not be
able to fully execute these projects due to:
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inability to attract and/or retain sufficient quantity of personnel with the skills required to bring these complex projects
to production on schedule and on budget;
significant delays in delivery of essential items or performance of services, cost overruns, supplier insolvency, or other
critical supply failure could adversely affect project development;
lack of government approval for projects;
civil disturbances, anti-development activities, legal challenges or other interruptions which could prevent access; and
drilling hazards or accidents or natural disasters.
We may not be able to compensate for, or fully mitigate, these risks.
Our international operations may be adversely affected by economic and political developments.
We have significant international operations, with approximately 40% of our 2012 total consolidated sales volumes coming
from international areas. This will be increasing as major development projects offshore West Africa and the Eastern
Mediterranean begin producing in 2013. We are also conducting exploration activities in these and other international areas.
Our operations may be adversely affected by political and economic developments, including the following:
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renegotiation, modification or nullification of existing contracts, such as may occur pursuant to future regulations
enacted as a result of recommendations of Israel's Interministerial Committee to Examine Government Policy on
Israel's Natural Gas Economy (Interministerial Committee), 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 foreign hydrocarbon-producing nations, such as
expropriation or nationalization of assets or termination of contracts, such as the termination of our Block 3 PSC by
the Ecuadorian government in 2010 pursuant to changes in Ecuador's hydrocarbon law;
disruptions caused by territorial or boundary disputes in certain international regions, including the Eastern
Mediterranean, where Lebanon has made claims related to our projects in Israeli waters and the Turkish government in
Ankara objected to exploratory activities conducted offshore the Republic of Cyprus;
changes in drilling or safety regulations in other countries as a result of the Deepwater Horizon Incident or other
incidents that have occurred, such as offshore Brazil and in China's Bohai Bay, which could increase costs and
development cycle time;
laws and policies of the US and foreign jurisdictions affecting foreign investment, taxation, trade and business
conduct;
foreign exchange restrictions;
international monetary fluctuations and changes in the relative value of the US dollar as compared with the currencies
of other countries in which we conduct business, such as Israel; and
other hazards arising out of foreign governmental sovereignty over areas in which we conduct operations.
Certain of these risks could be intensified by large crude oil or natural gas discoveries in areas where we are currently
conducting exploration activities, such as in the Eastern Mediterranean, offshore Nicaragua, or the Falkland Islands. Large
discoveries, such as ours in the Levant Basin, may have impacts on global natural gas supplies.
Such political and economic developments as mentioned above 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 government policies and regulation of oil
and gas development in the countries in which we operate.
Fiscal regimes impact oil and gas companies through laws and regulations governing royalties, taxes, resource access, or level
of government participation in oil and gas projects. 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 take, and a corresponding
decrease or increase in the revenues of an oil and gas company operating in that particular country. For example, the Petroleum
Profits Taxation Law, 2011, imposed additional income tax on oil and gas production in Israel. A large portion of our
production comes from Equatorial Guinea; therefore, changes in its fiscal regime could have a significant impact on our
operations. In addition, we cannot predict how government agencies or courts will interpret existing tax laws and regulations or
the effect such interpretations could have on our business.
Many countries are currently experiencing fiscal problems and sustained structural government budget deficits and lower tax
revenues triggered by the lingering effects of the global economic crisis of 2008, associated recession and current slower
economic growth rates. Higher unemployment and slower growth rates, coupled with a reduced tax base, have resulted in
reduced government revenues, while government expenditures continue to grow due to the costs of entitlements, subsidies and
economic stimulus programs. Many countries have generated significant budget deficits and sovereign debt levels with some
approaching insolvency. Demands on certain governments to undertake austerity measures in response to the European debt
crisis have resulted in increased social unrest. In addition, certain non-governmental organizations are promoting "tax
fairness", "fair share" payments, and income redistribution. Regulations enacted to achieve "tax fairness" or income
redistribution could result in increased tax burdens on individuals or corporations.
Due to pressures from financial markets or local constituents to address these negative fiscal situations and initiate deficit
reduction measures, many governments are seeking additional revenue sources, including increases in government take from
oil and gas projects.
In the US, on January 2, 2013, the President signed into law The American Taxpayer Relief Act of 2012 (the Act). The Act
extended through 2013 certain expired and expiring business tax provisions, including the research credit, bonus depreciation
and others. However, the Act did not settle the debate on deficit reduction as the bill delayed mandatory across-the-board
spending cuts known as sequestration, nor did it address increasing entitlement costs and fundamental tax reform. In recent
years, certain measures have been proposed that would alter current tax expense on oil and gas companies through: the repeal
of percentage depletion for oil and natural gas properties, the deferral of expensing intangible drilling and development costs
(IDC), the inability to expense costs of certain domestic production activities, and a lengthening of the amortization period for
certain geological and geophysical expenditures. It is likely that some of these proposals to increase taxes on the oil and gas
36
industry will continue to be reviewed by the US Congress in 2013 or future years. The enactment of some or all of these
proposals would have a significant negative impact on our capital investment, production and growth. In particular, we
estimate that the elimination of the current deductibility of IDC expenditures would impact our cash available for investment
and could curtail our domestic capital spending program by 15 - 25%.
In addition, although Congress recently passed, and the President signed into law, a bill that suspended the debt ceiling until
May 19, 2013, the long-term debt ceiling and federal budget deficit issues must be resolved. Congress must pass new
legislation and the President must sign it into law in order to avoid or mitigate these situations. At this time, substantial
uncertainty exists as to whether or how these matters will be resolved. Certain measures, if enacted too suddenly, could reduce
economic growth and increase the risk of a recession.
Changes in fiscal regimes have long-term impacts on our business strategy, and uncertainty makes it more difficult to formulate
capital investment programs. The implementation of new, or the modification of existing, laws or regulations impacting the
amount of government take could disrupt our business plans and negatively impact our operations in the following ways,
among others:
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restrict resource access or lease holding;
reduce exploration 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 project financing;
cause delay in or cancellation of development plans, which could also have a long-term negative impact on the
quantities of proved reserves we record and inhibit future production growth;
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 current 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;
restrict our ability to compete with imported volumes of crude oil or natural gas; and/or
adversely affect the price of our common stock.
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.
Violent acts resulting in loss of life and destruction of property occur around the world. Many incidents are driven by civil,
ethnic, religious or economic strife. In addition, the number of incidents attributed to various terrorist organizations has
increased significantly. We operate in regions of the world that have experienced such incidents or are in close proximity to
areas where violence has occurred including:
US and Europe Within the last decade, violent acts have occurred which specifically targeted citizens and property of the US
and other Western nations including the September 11, 2001 World Trade Center attack, the 2004 Madrid train bombing, the
2005 attack on London's public transportation system, and the 2012 attacks on US embassies in Libya, Egypt and Yemen.
Attacks on Western citizens and property occur not just on US and European soil, but worldwide.
West Africa In the countries of West Africa there have been numerous acts of piracy, kidnapping, civil strife, regional conflict,
cross-border violence, war, as well as violence associated with corruption, drug trafficking and regime changes. For example,
in January 2013, numerous workers at a natural gas facility in Algeria were taken hostage and some were killed. In 2012, the
government of Mali asked the United Nations to aid its defense against armed rebels. Also in 2012, militants in Nigeria
continued their attacks on residents and property, and engaged in cross border attacks into Cameroon. In addition, deadly labor
violence occurred in South Africa. Violence, loss of life and property damage associated with piracy in the Gulf of Guinea
have impacted several countries of West Africa as well as the international community.
Middle East Civil unrest, often accompanied by violence, has spread throughout the region. Protesters have demanded
economic and political reforms, and to date, there have been several regime changes. Civil unrest could continue to spread
throughout the region or grow in intensity, leading to regime changes resulting in governments that are hostile to the US, civil
wars, or regional conflict.
There have also been rising international tensions over Iran, which was censured by the United Nations over its nuclear
development activities. Certain countries have implemented economic sanctions and/or considered pre-emptive strikes on
suspected nuclear sites. Iranian officials have threatened retaliation by, among other actions, closing the Strait of Hormuz,
through which a significant portion of the global crude oil supply is transported.
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In November 2012, Israel and the Hamas militant group were engaged in air strikes and rocket attacks resulting in civilian
deaths. Although a cease-fire is currently in effect, some level of conflict is likely to continue. In December 2012, the Turkish-
Syrian border became militarized; US and Dutch NATO troops were deployed to defend against the perceived threat of a
Syrian missile attack, possibly with chemical weapons.
Central America There have been numerous acts of violence associated with drug trafficking and constant military and police
operations targeting organized crime. The existence of autonomous regions in Nicaragua could increase instability or conflict
with the central government.
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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volatility in global crude oil 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 world 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 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 resulting
in a halt or delay in our planned exploration activities, delayed development of major projects, or shut-in of producing
fields;
lack of availability of drilling rig, 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 complete disruption of our business
activities; and
capital market reassessment of risk and subsequent reallocation of capital to more stable areas making it more difficult
for 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.
Concentration of our operations in a few core areas may increase our risk of production loss.
Our operations are concentrated in five core areas: the DJ Basin, the Marcellus Shale, and the deepwater Gulf of Mexico in the
US, offshore West Africa, and the Eastern Mediterranean. These core areas provide approximately 85% of our current
production, each of our major development projects, and most of our exploration potential. During 2012, we initiated a non-
core divestiture program to high-grade and focus our portfolio, and sold certain non-core onshore US and North Sea assets.
As a result of these portfolio changes, our operations and production are concentrated in fewer areas, and more of our
production is from fewer wells. For example, approximately 20% of our 2012 production came from four offshore
developments. Although, individually, none of these core areas represent more than 33% of our 2012 total sales volumes,
disruption of our business in one of these areas, such as from an accident, natural disaster, government intervention, or other
event, would result in a greater impact on our production profile, cash flows and overall business plan than if we operated in a
larger number of areas.
We do not maintain business interruption (loss of production) insurance for all of our assets. Loss of production or limited
access to reserves in one of our core operating areas could have a significant negative impact on our cash flows and
profitability.
Exploration, development and production risks and natural disasters could result in liability exposure or the loss of
production and revenues.
Our operations are subject to hazards and risks inherent in the drilling, production and transportation of crude oil and natural
gas, including:
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injuries and/or deaths of employees, supplier personnel, or other individuals;
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pipeline ruptures and spills;
fires, explosions, blowouts and well cratering;
equipment malfunctions and/or mechanical failure on high-volume, high-impact wells;
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;
release of pollutants;
surface spillage of, or contamination of groundwater by, fluids used in hydraulic fracturing operations;
security breaches, cyber attacks, piracy, or terroristic acts;
theft or vandalism of oilfield equipment and supplies, especially in areas of increased activity such as the DJ Basin and
Marcellus Shale;
hurricanes, cyclones, windstorms, or “superstorms”, such as Hurricane Sandy which occurred in 2012, which could
affect our operations in areas such as the Gulf Coast, deepwater Gulf of Mexico, Marcellus Shale, Eastern
Mediterranean or offshore China;
• winter storms and snow which could affect our operations in the Rocky Mountain areas;
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unseasonably warm weather, which could affect third party gathering and processing facilities, such as occurred in the
Rocky Mountain areas during 2012;
volcanoes which could affect our operations offshore Equatorial Guinea;
flooding which could affect our operations in low-lying areas such as the Marcellus Shale;
harsh weather and rough seas offshore the Falkland Islands, which could limit certain 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.
Offshore development involves significant operational and financial risks.
We have ongoing major development projects in the deepwater Gulf of Mexico, offshore West Africa and offshore Eastern
Mediterranean. In addition, we are conducting offshore exploration activities in these and other international locations. In
certain areas or at certain times, there may be limited availability of suitable drilling rigs, drilling equipment, support vessels,
and qualified operating personnel. Deepwater drilling rigs are typically subject to long-term contracts. In addition, frontier
areas may lack the physical and oilfield service infrastructure necessary for production and transportation. As a result,
development of an offshore discovery, such as Gunflint, Alen, Tamar, or Leviathan, may be a lengthy process and require
substantial capital investment. Difficulty and delays in consistently obtaining drilling rigs and other equipment and services at
acceptable rates may lead to project delay, increased costs, inability to meet delivery requirements, and/or inability to forecast
production, which could prevent the realization of our targeted return on capital or lead to unexpected future losses.
Deepwater frontier areas, especially in international locations such as offshore the Falkland Islands, Nicaragua or Sierra Leone,
may lack the equipment and services necessary for rapid subsea intervention, containment, capture and shut-in capacity in the
case of a well accident or spill. Spill containment and cleanup activities are costly. In addition, the resulting regulatory costs,
civil or criminal fines or sanctions, results of third party lawsuits, as well as associated legal and support expenses, including
costs to address negative publicity about us, could well exceed the actual costs of containment and cleanup. As a result, a well
spill or accident could result in substantial liabilities for us, and have a significant negative impact on our earnings, cash flows,
liquidity and financial position.
Many offshore areas are subject to hazardous conditions, such as harsh weather and rough seas offshore the Falkland Islands or
hurricanes in the Gulf of Mexico, which can limit certain exploration or development activities or increase the risk of accident.
Development drilling may not result in commercially productive quantities of oil and gas reserves.
Our exploration success has provided us with a number of major development projects on which we are moving forward. We
depend on these projects to provide long life, 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.
For example, in new development areas such as the Marcellus Shale, Gunflint, Leviathan or Cyprus Block 12, available data
may not allow us to completely know the extent of the reservoir or choose 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. Projects in
frontier areas may require the development of special technology for development drilling or well completion and we may not
have the knowledge or expertise in applying new technology. Our efforts may result in a dry hole or a well that finds
noncommercial quantities of hydrocarbons. Development drilling has the same legal and physical risks as exploratory drilling,
which can result in the drilling of a development dry hole or the incurrence of substantial development costs without a
corresponding increase in proved reserves.
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All costs of development drilling and other development activities are capitalized, even if the activities do not result in
commercially productive quantities of oil and gas reserves. This puts a property at higher risk for future impairment if
commodity prices decrease or operating or development costs increase.
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, in areas of high activity and demand in which we concentrate, such as
the DJ Basin and the Marcellus Shale, we may experience delays in obtaining well completion rigs and services. Frontier areas
may not have adequate infrastructure for gathering, processing or transportation, and production may be delayed until they are
constructed. This results in a decrease in current cash flows and reduces the return on our investment.
Costs of drilling, completing and operating wells are often uncertain, and cost factors can adversely affect the economic
viability of a project. Even a development project that is currently economically viable can become uneconomic in the future if
commodity prices decrease or operating or development costs increase, resulting in impairment charges and a negative impact
on our results of operations.
Our operations could be adversely affected by future changes in laws and regulations which may occur as a result of the
Deepwater Horizon Incident and other recent incidents.
In recent years, several oil spills have highlighted the dangers associated with exploration and production activities in
deepwater. In 2010, the drilling rig Deepwater Horizon sank after a blowout and fire. The resulting leak caused a large oil spill
in the Gulf of Mexico. In 2011, leaks attributed to exploration and production activities occurred offshore the coasts of Brazil
and Nigeria and in China's Bohai Bay. In 2012, several workers were injured and some were missing and presumed dead as the
result of a fire that erupted on an oil platform in the shallow water Gulf of Mexico, and a drilling rig being towed offshore
Alaska broke away from the tugboat and ran aground.
In the US, the legislative and regulatory response to the Deepwater Horizon Incident is ongoing. In 2010, the US Department of
the Interior issued new rules designed to improve drilling and workplace safety, and various Congressional committees began
pursuing legislation to regulate drilling activities and increase liability. In January 2011, the President's National Commission
on the BP Deepwater Horizon Oil Spill and Offshore Drilling released its report, recommending that the federal government
require additional regulation and an increase in liability caps. In 2011, the European Commission recommended that new
legislation be enacted to enhance the safety of offshore oil and gas activities and, in 2012, established the European Union
Offshore Oil and Gas Authorities Group.
In the US, additional regulatory review, slower permitting processes and increased oversight have resulted in longer
development cycle time for our deepwater Gulf of Mexico projects. Cycle time is the length of time it takes for a project to
progress from first discovery to first production, and longer development cycle times could result in lower rates of return on our
investments.
Increased regulation impacting our activities in the Gulf of Mexico and other deepwater areas could result in extensive efforts
to ensure compliance and incremental compliance costs. A significant delay or cancellation of our planned Gulf of Mexico
deepwater exploratory activities will reduce our longer term ability to replace reserves, resulting in a negative impact on
production over time. To the extent current exploration activities are significantly delayed, a gap could occur in our long-term
production profile with a negative impact on our operating results and cash flows.
There have also been discussions regarding the establishment of a new industry mutual response fund in which companies
would be required to participate and which would be available to pay for clean up and consequential damages arising from an
oil spill.
Other countries are also considering additional regulation. In the European Union there have been demands for temporary bans
on new deepwater drilling and/or additional safety regulation.
Future legislation or regulation is also likely to result in substantial increases in civil or criminal fines or sanctions. Such fines
or sanctions could well exceed the actual cost of containment and cleanup associated with a well incident or spill.
Governmental fines or penalties could also be excessive.
We are monitoring legislative and regulatory developments; however, the full legislative and regulatory response to the
Deepwater Horizon Incident and other oil spills and accidents is not yet known. Further expansion of safety and performance
regulations or an increase in liability for drilling 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 in the deepwater Gulf of Mexico or other locations,
resulting in longer development cycle times;
result in additional operating costs;
divert our cash flows from capital investments in order to maintain liquidity;
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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.
The magnitude of our offshore Eastern Mediterranean discoveries will present financial and technical challenges for us
due to the large-scale development requirements.
We are currently evaluating potential development scenarios for Leviathan and Cyprus Block 12. Due to the scale of these
discoveries, realization of their full economic value depends on the ability to export via pipeline or LNG. Each of these
development options would require a multi-billion dollar investment and require a number of years to complete.
As a result, we have been seeking partners to provide technical and financial support as well as midstream and downstream
expertise. In December 2012, we and our existing partners in the Leviathan project announced that we had agreed in principle
on a proposal to sell a 30% WI in the Leviathan licenses to Woodside Energy Ltd. (Woodside). The transaction is subject to the
negotiations and execution of definitive agreements between the parties, as well as customary approvals, prior to closing.
Failure to reach a definitive agreement with Woodside could result in a delay in the Leviathan development project.
In Israel, the Interministerial Committee, which was charged with the task of proposing a government policy for developing the
natural gas economy in Israel, issued its final report in 2012. We are monitoring the activities of the Interministerial Committee
to assess the possible impact, positive or negative, of any resulting laws or regulations on our business. Certain changes in
Israel's market, fiscal, and/or regulatory regimes occurring as a result of Interministerial Committee recommendations could
delay or reduce the profitability of our Tamar and/or Leviathan development projects and render future exploration and
development projects uneconomic.
The Israeli Antitrust Commissioner has been reviewing Israel's domestic natural gas sales and ownership in offshore blocks and
leases. He has publicly expressed concerns regarding ownership concentration on exploration blocks and development projects
and its potential impacts on a competitive domestic natural gas price environment and end user electricity costs. We have
cooperated with the Commission's review and, at this time, cannot predict the outcome.
Restrictions on resource access or controls over pricing could have a negative impact on our business including reduction on
future growth rates, profitability and cash flows.
Failure to execute successful development scenarios for Leviathan and Cyprus Block 12 could result in damage to our
reputation, limit growth in value and have negative effects on our operating results.
Failure of our partners to fund their share of development costs or obtain project financing could result in delay or
cancellation of future projects, thus limiting our growth and future cash flows.
Some of our major development projects entail significant capital expenditures and have long development cycle times. For
example, our joint venture arrangement with CONSOL provides for the long-term development of our Marcellus Shale acreage.
In the Eastern Mediterranean, each of our natural gas development options would require a multi-billion dollar investment and
span multiple years from sanction to production.
As a result, 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 project financing arrangements. Factors which could
reduce partners' available cash flows or impair their ability to obtain adequate project financing include, among others:
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declines in commodity prices, which reduce revenues and available cash flows;
changes in fiscal regimes impacting royalties, taxes, fees, resource access, or level of government participation in
projects;
delay in government project approval, which could have a negative impact on the ability to obtain financing;
downgrades in credit rating or liquidity problems;
increased banking regulation which could reduce access to traditional sources of funding or make funding more
expensive; and
regional conflict, which could result in capital market reassessment of risk and withdrawal of capital to more stable
areas.
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If these issues occurred and impacted our project partners, it could result in a delay or cancellation of a project, resulting in our
inability to replace reserves and budgeted production, negatively impacting the timing and receipt of planned cash flows and
expected profitability.
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 (OECD) Anti-Bribery Convention
generally prohibit improper payments to foreign officials for the purpose of obtaining or keeping business. The scope and
enforcement of anti-corruption laws and regulations may vary. The UK Bribery Act of 2010, which became effective in 2011, is
broader in scope than the FCPA and applies to public and private sector corruption and contains no facilitating payments
exception.
The import/export of equipment and supplies necessary for oil and gas exploration and development activities, as well as the
export of crude oil 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 greater import or export restrictions. In addition, the US
government imposes economic and trade sanctions against certain foreign countries and regimes, such as Iran and Syria. 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.
In certain areas, law enforcement may be more robust and enhanced by significant new incentives for whistleblowers.
Violations of any laws or regulations caused by either failure of our internal controls related to regulatory compliance or failure
of our employees to comply with our internal policies could result in substantial civil or criminal fines, sanctions, or loss of our
license to operate. In addition, as we continue to farm-in to exploration opportunities with new partners in new geographical
locations, the risk of actual or alleged violation increases. Actual or alleged violations could damage our reputation, be
expensive to defend, and impair our ability to do business.
Derivatives regulation included in current or proposed financial legislation and rulemaking could impede our ability to
manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating
commodity prices and interest rates.
The Dodd-Frank Act, which was passed by Congress and signed into law in July 2010, contains significant derivatives
regulation, including a requirement that certain transactions be cleared on exchanges and a requirement to post collateral
(commonly referred to as “margin”) for such transactions. The Act provides for a potential exception from these clearing and
collateral requirements for commercial end-users, such as us, and it includes a number of defined terms that will be used in
determining how this exception applies to particular derivative transactions and the parties to those transactions. As required
by the Dodd-Frank Act, the Commodities Futures and Trading Commission (CFTC) has promulgated numerous rules to define
these terms.
In addition, it is possible that the CFTC, in conjunction with prudential regulators, may mandate that financial counterparties
entering into swap transactions with end-users must do so with credit support agreements in place, which could result in
negotiated credit thresholds above which an end-user must post collateral.
We use derivative instruments with respect to a portion of our expected crude oil and natural gas production in order to reduce
the impact of commodity price uncertainty and enhance the predictability of cash flows relating to the marketing of our
production and in support of our capital investment program. We use interest rate derivative instruments to minimize the impact
of interest rate fluctuations associated with anticipated debt issuances. As commodity prices increase or interest rates decrease,
our derivative liability positions increase; however, given our current investment grade status, none of our current derivative
contracts require the posting of margin or similar cash collateral when there are changes in the underlying commodity prices or
interest rates that are referred to in these contracts.
Depending on the rules and definitions adopted by the CFTC and prudential regulators, we could be required to post significant
amounts of collateral with our dealer counterparties for our derivative transactions. A sudden margin call triggered by rising
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commodity prices or falling interest rates would have an immediate negative impact on our business plan, forcing us to divert
capital from exploration, development and production activities. Requirements to post cash collateral could result in negative
impacts on our liquidity and financial flexibility and also cause us to incur additional debt and/or reduce capital investment. In
addition, a requirement for our counterparties to post collateral would likely result in additional costs being passed on to us,
thereby decreasing the effectiveness of our hedges and our profitability. In addition, the final CFTC rules may also require the
counterparties to our derivative instruments to spin off some of their derivative activities to a separate entity, which may not be
as creditworthy as the current counterparty.
Disclosure of certain operating information as required by Section 1504 of the Dodd-Frank Act could have a negative
impact on our operations.
On August 22, 2012, the SEC issued final rules: Disclosure of Payments by Resource Extraction Issuers (Final Rules), as
required by the Dodd-Frank Act. As a result, beginning in 2014, we must provide information about the type and total amount
of payments made for each project related to the commercial development of oil, natural gas, or minerals, and the type and total
amount of payments made to each government. If these required disclosures conflict with the confidentiality obligations of our
subsidiaries or the general laws of the respective countries in which they operate, there could be substantial negative impacts on
our operations. Disclosure of certain information could have the following negative impacts, among others, on our operations:
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compromise of the security of our employees by subjecting them to detention, arrest, claims of espionage and/or
prosecution;
loss of our license to operate in countries where the laws and regulations or terms of production sharing or other
contracts prohibit disclosures of certain information, resulting in a reduction in our profitability;
decrease in our ability to compete for new sources of reserves with state-controlled national oil companies or large
multi-national companies not subject to disclosures under the Final Rules; and
reduction in profitability and cash flows and a decrease in the price of our common stock.
We face various risks associated with global populism.
Due in part to the upheaval and uncertainty caused by global economic events including the financial crisis and resulting
recession that began in 2008, higher unemployment, and government austerity measures, populist sentiments have risen.
Populism is directed against perceived economic and social inequality. During 2012, workers across the European Union,
including Spain, Portugal, Greece and Belgium, engaged in strikes and demonstrations to protest cuts in government spending,
pensions and entitlements and increases in taxes. In many situations, social media channels have been used to organize
protesters and increase public participation.
Certain political and non-governmental organizations are promoting "tax fairness", or "fair share". "Tax fairness" claims to
create a fair, clear and equivalent tax system for all taxpayers by limiting legislation and rules that benefit one segment of the
tax-paying population over another. However, the impact of such changes could be the loss of business incentives and/or
increased taxes for individuals or corporations.
Populist activities could result in the following:
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increased regulation of our business;
increased regulation of the banking industry; and
increased corporate income taxes.
Our need to incur costs associated with responding to these developments or complying with any resulting new legal or
regulatory requirements resulting from these activities that are substantial and not adequately provided for, could 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 operations.
We face various risks associated with the trend toward increased anti-development activity.
Opposition toward oil and gas drilling and development activity has been growing globally. Companies in the oil and gas
industry, such as us, are often the target of activist efforts from both individuals and non-governmental organizations regarding
safety, human rights, environmental compliance, transparency, anti-corruption, and business practices.
Anti-development activists are working to, among other things, reduce access to national and state government lands; delay or
cancel certain projects such as offshore drilling, shale development, and pipeline construction; limit or ban the use of hydraulic
fracturing; or block activity in sensitive environmental areas such as the Arctic. For example, in 2012, the City of Longmont,
Colorado voted to ban hydraulic fracturing activities within city limits. Environmental activists have challenged decisions to
grant air-quality permits for offshore drilling and have advocated for increased regulations on shale drilling and hydraulic
fracturing in the US. Activists have recently attempted to prevent exploratory drilling in the Arctic.
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Activities engaged in by some non-governmental organizations seeking to increase revenue transparency, limit foreign
government corruption, increase "tax fairness" or "fair share" payments, or promote income redistribution could result in
regulatory changes which could increase our taxes and decrease our profitability.
In addition, the use of social media channels can be used to cause rapid, widespread reputational harm.
Future activist efforts could result in the following:
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delay or denial of drilling permits;
shortening of lease terms or reduction in lease size;
restrictions on installation or operation of gathering or processing facilities;
restrictions on the use of certain operating practices, such as hydraulic fracturing;
reduced access to water supplies or restrictions on water disposal;
limited access or damage to or destruction of our property;
legal challenges or lawsuits;
increased regulation of our business;
damaging publicity about us;
increased costs of doing business;
reduction in demand for our products; and
other adverse effects on our ability to develop our properties and expand production.
Our need to incur costs associated with responding to these initiatives or complying with any resulting new legal or regulatory
requirements resulting from these activities that are substantial and not adequately provided for, could have a material adverse
effect on our business, financial condition and results of operations.
A cyber incident could result in information theft, data corruption, operational disruption, and/or financial loss.
The oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including
certain exploration, development and production activities. For example, software programs are used to interpret seismic data,
manage drilling rigs, production equipment and gathering and transportation systems, conduct reservoir modeling and reserves
estimation, and for compliance reporting. The use of mobile communication devices has increased rapidly. Industrial control
systems such as SCADA (supervisory control and data acquisition) now control large scale processes that can include multiple
sites and long distances, such as power generation and transmission, communications and oil and gas pipelines.
We depend on digital technology, including information systems and related infrastructure as well as cloud application 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 and for many 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 complexity of the technologies needed to extract oil and gas in increasingly
difficult physical environments, such as deepwater, ultra-deepwater and shale, and global competition for oil and gas resources
make certain information more attractive to thieves.
As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have
also 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. For
example, in 2012, a wave of network attacks impacted Saudi Arabia's oil industry and breached financial institutions in the US.
Certain countries, including China, Russia and Iran, are believed to possess cyber warfare capabilities and are credited with
attacks on American companies and government agencies. SCADA-based systems are potentially more vulnerable to cyber
attacks due to the increased number of connections with office networks and the internet.
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.
A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our
business plans and negatively impact our operations in the following ways, among others:
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unauthorized access to seismic data, reserves information or other sensitive or proprietary information could have a
negative impact on our ability to compete for oil and gas resources;
data corruption, communication interruption, or other operational disruption during drilling activities could result in a
dry hole cost or even drilling incidents;
data corruption or operational disruption of production infrastructure could result in loss of production, or accidental
discharge;
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a cyber attack on a vendor or service provider could result in supply chain disruptions which could delay or halt one of
our major development projects, effectively delaying the start of cash flows from the project;
a cyber attack on a third party gathering or pipeline service provider could prevent us from marketing our production,
resulting in a loss of revenues;
a cyber attack involving commodities exchanges or financial institutions could slow or halt commodities trading, thus
preventing us from marketing our production or engaging in hedging activities, resulting in a loss of revenues;
a cyber attack which halts activities at a power generation facility or refinery using natural gas as feed stock could
have a significant impact on the natural gas market, resulting in reduced demand for our production, lower natural gas
prices, and reduced revenues;
a cyber attack on a communications network or power grid could cause operational disruption resulting in loss of
revenues;
a deliberate corruption of our financial or operational data could result in events of non-compliance which could lead
to regulatory fines or penalties; and
business interruptions could result in expensive remediation efforts, distraction of management, damage to our
reputation, or a negative impact on the price of our common stock.
Although to date we have not experienced any material losses relating to cyber attacks, there can be no assurance that we will
not suffer such losses in the future. 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.
Federal or state hydraulic fracturing legislation could increase our costs or restrict our access to oil and gas reserves.
Hydraulic fracturing using fluids other than diesel is currently exempt from regulation under the federal Safe Drinking Water
Act, but opponents of hydraulic fracturing have called for further study of the technique's environmental effects and, in some
cases, a moratorium on the use of the technique. In past Congresses, several bills were filed that, if implemented, would have
subjected all hydraulic fracturing to regulation under the Safe Drinking Water Act. It is likely that similar bills will be
introduced in the current Congress. Further, the EPA's Office of Research and Development (ORD) is conducting a scientific
study to investigate the possible relationships between hydraulic fracturing and drinking water. Several states are considering
legislation to regulate hydraulic fracturing practices, including restrictions on its use in environmentally sensitive areas. Some
municipalities have significantly limited or prohibited drilling activities, or are considering doing so. For example, in
November 2012, the City of Longmont, Colorado voted to ban hydraulic fracturing activities within city limits.
Although it is not possible at this time to predict the final outcome of the ORD's study or the requirements of any additional
federal or state legislation or regulation regarding hydraulic fracturing, any new federal or state, or local restrictions on
hydraulic fracturing that may be imposed in areas in which we conduct business, such as the DJ Basin or Marcellus Shale areas,
could significantly increase our operating, capital and compliance costs as well as delay or halt our ability to develop oil and
gas reserves. See Items 1. and 2. Business and Properties - Hydraulic Fracturing.
The marketability of our DJ Basin, Marcellus Shale, and deepwater Gulf of Mexico production is dependent upon
transportation and processing facilities over which we may have no control.
The marketability of our production from the DJ Basin, Marcellus Shale, and deepwater 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 and natural gas produced from these areas through gathering systems and pipelines, some of which we do not
own. The lack of availability of 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. Although 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. Activist or other efforts may delay or halt the construction of additional pipelines or
facilities.
Third-party systems and facilities may not be available to us in the future at a price that is acceptable to us. 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 production, thereby harming our business and, in turn, our
results of operations, cash flows, and financial condition.
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Restricted land access could reduce our ability to explore for and develop crude oil and natural gas reserves.
Our ability to adequately explore for and develop oil and gas 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 or state land use regulations, such as recent changes in setback requirements expected to be approved
by the COGCC, 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, such as the recent ban on hydraulic fracturing enacted by the City of
Longmont, Colorado;
landowner opposition to infrastructure development, such as recent landowner challenges to the use of eminent
domain to gain access to land for the extension of the Keystone pipeline through Texas, or to onshore delivery points
in Israel;
regulation of federal land by the BLM, which has proposed rules for hydraulic fracturing on federally-owned land, and
which can limit our access to a significant portion of our Nevada acreage;
anti-development activities, which can reduce our access to leases through legal challenges or lawsuits, occupation of
drilling sites, or damage to equipment;
disputes regarding leases, such as the Butler v. Powers case in Pennsylvania; 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 portfolio.
Our entry into new exploration ventures in areas in which we have no prior experience subjects us to additional risks.
During 2012, we entered into three new, high-potential areas, none of which currently has crude oil or natural gas production:
Northeast Nevada, offshore the Falkland Islands, and offshore Sierra Leone. We are also planning to drill our first exploratory
well offshore Nicaragua. These arrangements represent entry into new geographical areas in which we have no prior
experience. Our activities will be subject to many risks including, among others:
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exploration activities in frontier areas may not result in commercially productive quantities of crude oil and natural gas
reserves;
exploration activities on federal lands in Northeast Nevada subject us to additional regulatory requirements as
compared with such activities conducted on private land;
the remote location of the Falkland Islands makes it more difficult and time-consuming to transport personnel,
equipment and supplies;
the operating environment offshore the Falkland Islands, similar to that offshore the Shetland Islands in the North Sea,
includes harsh weather and rough seas which could limit seismic and other exploration activities during certain
periods; and
there have been numerous acts of piracy, kidnapping, civil strife, regional conflict, cross-border violence, and war, as
well as violence associated with corruption, drug trafficking and regime changes in the countries of West Africa which
could disrupt our operations offshore Sierra Leone.
The people of the Falkland Islands have the right to self-determination, and the Falkland Islands is a United Kingdom Overseas
Territory by choice. However, the government of Argentina persists in questioning its status. Actual or perceived threats from
Argentina or incursion by Argentina into the Falkland Islands territorial waters could result in disruptions to our planned
activities. This risk could be intensified if commercial quantities of oil or natural gas are discovered. We may not be able to
compensate for or fully mitigate these risks.
Our ability to produce crude oil and natural gas 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 activities require the use of water. For example, the hydraulic fracturing process which we employ to produce
commercial quantities of crude oil and natural gas from many reservoirs, including the DJ Basin and Marcellus Shale, require
the use and disposal of significant quantities of water. In certain areas, there may be insufficient local aquifer capacity to
provide a source of water for drilling activities. Water must be obtained from other sources and transported to the drilling site.
Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, could adversely
impact our operations in certain areas. Moreover, the imposition of new environmental initiatives and regulations could include
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restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not
limited to, produced water, drilling fluids and other materials associated with the exploration, development or production of
natural gas.
Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface
water or groundwater necessary for hydraulic fracturing of wells may increase our 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.
Our Marcellus Shale joint venture subjects us to certain financial, operational and legal obligations and additional risks
associated with development activities in that region.
We have committed to make significant capital expenditures in the Marcellus Shale, including a Carried Cost Obligation of
approximately $2.1 billion, and have agreed to other operational and legal obligations. If we do not meet our financial
commitments or perform our other obligations on a timely basis, our rights to participate in the joint venture, and our
anticipated operations in the Marcellus Shale, could be adversely affected.
We plan to drill numerous wells in the Marcellus Shale over a multi-year period. These activities will be subject to many risks
including, among others:
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development drilling in emerging resource plays such as the Marcellus Shale may not result in commercially
productive quantities of crude oil and natural gas reserves;
• we have less exploration and development experience in the Marcellus Shale than we have in other areas and limited
information regarding ultimate recoverable reserves and production decline rates; therefore, our estimates of
economically recoverable quantities of crude oil and natural gas reserves may vary substantially and actual production,
revenue and expenditures with respect to our reserves likely will vary, possibly materially, from estimates;
the high level of current and planned development activity in the Marcellus Shale may result in increased competition
for drilling rigs and oilfield services such as hydraulic fracturing, gathering, processing and/or transportation, thus
hindering our ability to develop our reserves and market our production;
activism in New York, Pennsylvania and West Virginia against oil and gas development activities, particularly
regarding the use of hydraulic fracturing, could, among other things, delay or limit our access to crude oil and natural
gas reserves;
additional environmental regulation or legislation could result in additional development and/or production costs;
potential enactment of severance taxes or additional fees in Pennsylvania, such as the well impact fee enacted by the
Pennsylvania legislature in 2012, would likely result in a lower rate of return on our development project; and
our inability to locate sufficient amounts of water, or dispose of or recycle water used in our operations, could hinder
our ability to develop our reserves or increase our development and operating costs; and
development activity in the Marcellus Shale places additional burdens on our financial resources and internal financial
controls.
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We may not be able to compensate for or fully mitigate these risks. See Items 1. and 2. Business and Properties - Entry Into
Marcellus Shale joint venture.
Indebtedness may limit our liquidity and financial flexibility.
As of December 31, 2012, we had $4.1 billion of debt, of which $372 million is due within 12 months. Our indebtedness
represented 33% of our total book capitalization (sum of debt plus shareholders' equity) at December 31, 2012.
Our indebtedness affects our operations in several ways, including the following:
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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) will not
exceed 65% at any time, which may limit our ability to borrow additional funds, thereby affecting our flexibility in
planning for, and reacting to, changes in the economy and in our industry;
additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other
purposes may have higher costs and more restrictive covenants;
changes in the credit ratings of our debt 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
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• 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 and we may default on our debt obligations. Our
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ability to meet our debt obligations and service our debt depends on future performance. General economic conditions, crude
oil, natural gas, and NGL 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 12. Long-Term Debt.
Unavailability of capital resources at reasonable cost could have a negative impact on our liquidity and limit our growth.
The capital markets are currently less constrained than they were in the period subsequent to the global economic crisis of
2008. However, certain situations are increasing pressure on the capital markets and could cause funding sources to become
constrained again. These situations include:
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the European debt crisis persists, with governments and banks requiring more economic assistance;
fiscal situations are also worsening in OECD countries due to lingering effects of recession including slower growth
rates;
• Basel III banking regulation impacts the amount and nature of capital required to be held by banks;
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quantitative easing programs generally weaken the currency of the country launching the stimulus, and discontinuance
of such programs can result in spikes in interest rates;
the risk of a potential negative stock market event, such as a sharp price decline or even a “crash”, is intensified by
lack of significant improvement in the US fiscal situation and fear that a combination of spending cuts and new taxes
could push the country back into recession; and
interest rates could rise if the US debt ceiling is not raised in a timely manner.
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These situations have a negative impact on the availability and cost of capital. If we or our partners are unable to obtain
financing, future development projects could be delayed or canceled, thus limiting our growth and future cash flows.
Failure to resolve long-term US fiscal issues, primarily the federal budget deficit and the debt ceiling, could have a negative
impact on the economy, slowing growth and reducing demand for our products.
In the coming months, the US will face three critical deadlines: on March 1, mandatory across-the-board spending cuts
(sequestration) are scheduled to take effect; by late March a new spending bill must be passed to fund the federal government,
and in May, the debt ceiling suspension will expire.
Congress and the Administration are deeply divided over the issues and there is a lack of consensus on the extent and timing of
an increase in the borrowing limit and whether deficit reductions should come from spending cuts, tax increases or a
combination of both. In addition, the US government has failed to address increasing entitlement costs and fundamental tax
reform. Failure to solve these long term fiscal challenges could undermine the economic recovery, reducing demand and
slowing growth. For example:
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if the debt ceiling is not raised in a timely manner, the US could default on its debt and/or experience a reduction in its
credit rating, and interest rates could increase;
servicing the US debt diverts resources from investments that would spur economic growth;
increased borrowing means that the US government competes with businesses for financing and businesses may be
unable to secure funds for expansion;
a federal deficit reduction program, if undertaken too rapidly, could put the economy back into recession; and
austerity measures undertaken to reduce the US deficit could result in increased social unrest, such as is occurring in
the European Union.
To the extent fiscal issues are not addressed, slower economic growth and a reduction in demand for our products could occur.
Such developments could have a significant negative impact on our earnings, cash flows, access to capital, liquidity and
financial position. In addition, economic uncertainty makes it more difficult for us to design our exploration and development
strategy and related capital investment programs, which are typically formulated years in advance.
Our operations may be adversely affected by the European debt crisis.
During 2011, the long term structural deficits in numerous European nations coupled with the deterioration of the economic
outlook led the weaker nations to a liquidity and solvency crisis. Eurozone leaders have made numerous attempts to solve this
debt crisis, but to date a sustainable long term solution has not been implemented and much uncertainty remains. The crisis has
had a negative impact on major European banks which historically were significant providers of credit to the energy sector,
globally and in the US. In 2012, Cyprus requested a financial rescue in order to recapitalize Cypriot banks, which had been
weakened by their exposure to the Greek economy.
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Failure to successfully resolve the debt crisis could lead to significant losses for debt holders, including major European banks
and investors, triggering additional capital requirements. In the worst case, the crisis could lead to the voluntary exit or
expulsion of certain countries from the Euro currency block and/or a collapse of the eurozone financial system. A break up of
the eurozone would be a deeply disruptive global economic event. The ongoing crisis continues to have a negative impact on
the European economy. A prolonged downturn could disrupt the current US recovery and weaken global trade, hamper key
emerging markets such as China and India, and result in another global recession with reduced demand and lower prices for the
oil and gas we produce.
A eurozone debt crisis could have the following impacts, among others:
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disruption of the Euro currency system and/or changes in currency regimes;
disruption of the payment and settlement system;
severe inflation due to currency depreciation;
loss of access to energy markets;
sovereign and corporate defaults on euro-denominated debt;
failures of banks or financial systems or reduced ability of banks to lend due to higher funding costs;
devaluation of assets; and
regional economic recession which could spread globally.
The economic developments mentioned above could have a significant negative impact on our earnings, cash flows, access to
capital, liquidity and financial position.
Increased banking regulation could result in reduced access to traditional sources of funding and limit our growth.
In response to the global economic crisis of 2008, banking regulation has increased. New regulation includes the Basel III rules
issued by the Basel Committee on Banking Supervision and the Final Report of the UK's Independent Commission on Banking
(also known as the Vickers Report). These, and other potential regulations being considered by governing bodies in the US and
other countries, are expected to impact the amount of capital required to be held by banks and the nature of such capital. As a
result, traditional lending practices could change, resulting in more restricted access to funds or reduced availability of funds at
rates and terms we consider to be economic. Increased regulation could also negatively impact the project finance market, even
for investment grade companies such as we are, and reduce our ability to obtain funding for the capital requirements of future
major development projects, such as a potential LNG project. Inability of us and/or our partners to obtain financing could result
in delay or cancellation of future development projects, thus limiting our growth and future cash flows.
Slower global economic growth rates may materially adversely impact our operating results and financial position.
The recovery from the global economic crisis of 2008 and resulting recession has been slow and uneven. Market volatility and
reduced consumer demand have increased economic uncertainty, and the current global economic growth rate is slower than
what was experienced in the years leading up to the crisis. Many developed countries are constrained by long term structural
government budget deficits and international financial markets and credit rating agencies are pressing for budgetary reform and
discipline. This need for fiscal discipline is balanced by calls for continuing government stimulus and social spending as a
result of the impacts of the global economic crisis. As major countries implement government fiscal reform, such measures, if
they are undertaken too rapidly, could further undermine economic recovery, reducing demand and slowing growth. Impacts of
the crisis could spread to China and other emerging markets, which have fueled global economic development in recent years,
slowing their growth rates, reducing demand, and resulting in further drag on the global economy.
Global economic growth drives demand for energy from all sources, including fossil fuels. A lower future economic growth
rate is likely to result in decreased demand growth for our crude oil and natural gas production. A decrease in demand,
notwithstanding impacts from other factors, could potentially result in lower commodity prices, which would reduce our cash
flows from operations, our profitability and our liquidity and financial position.
The adoption of GHG emission or other environmental legislation could result in additional operating costs, create delays in
our obtaining air pollution permits for new or modified facilities, and reduce demand for the crude oil and natural gas we
produce.
In recent years, each house of Congress has considered legislation to address GHG emissions, such as the American Clean
Energy and Security Act of 2009, also known as the Waxman-Markey Bill, passed by the House of Representatives, and The
Clean Energy Jobs and American Power Act, or the Boxer-Kerry Bill, introduced to the Senate. Future legislation could include
mandatory carbon dioxide emissions goals, measures to encourage use of renewable energy over fossil-based fuels, higher
penalties and fines for violations of various environmental laws, or other regulations designed to curb GHG emissions.
One measure considered frequently has been the establishment of a “cap and trade” system for restricting GHG emissions in
the US. Under such system, certain sources of GHG emissions would be required to obtain GHG emission “allowances”
corresponding to their annual emissions of GHGs. The number of emission allowances issued each year would decline as
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necessary to meet overall emission reduction goals. As the number of GHG emission allowances declines each year, the cost or
value of allowances would be expected to escalate significantly.
The EPA requires regulated facilities and oil and natural gas operators meeting a certain emissions threshold to report GHG
emissions. Beyond measuring and reporting, the EPA has issued an “Endangerment Finding” under section 202(a) of the Clean
Air Act, concluding GHG pollution threatens the public health and welfare of current and future generations and has indicated
that it will use data collected through the reporting rules to decide whether to promulgate future GHG limits.
Even if federal GHG legislation or regulation is not adopted, almost one-half of the states have taken action to reduce GHG
emissions through the development of GHG emissions inventories and the establishment of regional GHG cap and trade
programs. Most of the state-level initiatives have focused on large sources of GHG emissions. It is possible, however, that
smaller sources could become subject to state regulation of GHGs.
During 2012, approximately 56% of our total crude oil production, 57% of our total natural gas production, and 100% of our
NGL production from total consolidated volumes was derived in the US. Therefore, any laws or regulations that may be
adopted to restrict or reduce emissions of US GHGs could require us to incur additional operating costs and increase our
development cycle time. In addition, we could be required to make significant capital expenditures to comply with new
environmental legislation, which would cause us to divert capital from exploration, development and production activities.
GHG regulation may make our products less desirable than lower GHG emitting energy sources, such as wind and solar. It is
possible, however, that GHG regulation may increase the competitiveness of our products with respect to higher GHG emitting
energy sources, such as coal. At this time it is impossible to predict with certainty how a GHG regulation scheme would affect
the oil and gas market.
We face significant competition and many of our competitors have resources in excess of our available resources.
We operate in the highly competitive areas of crude oil and natural gas exploration, exploitation, acquisition and production.
We face intense competition from:
large multi-national, integrated oil companies;
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state-controlled national oil companies;
• US independent oil and gas companies;
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service companies engaging in exploration and production activities; and
private 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;
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• marketing our crude oil and natural gas production;
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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 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.
Exploratory drilling may not result in the discovery of commercially productive reservoirs.
We depend on exploration success to provide growth in production and reserves and are planning an active exploratory drilling
program in 2013. Exploratory drilling requires significant capital investment and does not always result in commercial
quantities of hydrocarbons or new development projects. For example, we incurred dry hole expense in 2012 associated with
the Deep Blue exploratory well in the deepwater Gulf of Mexico and the Trema exploratory well offshore Cameroon.
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.
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:
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title problems;
near-term lease expiration;
decisions impacting allocation of capital;
compliance with environmental and other governmental requirements;
increases in the cost of, or shortages or delays in the availability of, drilling rigs, equipment and qualified personnel;
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unexpected drilling conditions;
pressure or other irregularities in formations;
equipment failures or accidents; and
adverse weather conditions.
In addition, companies seeking new reserves often face more difficult environments, such as oil sands, deepwater, or ultra-
deepwater, and often need to develop or invest in new technologies. This increases cost as well as drilling risk.
For certain capital-intensive deepwater Gulf of Mexico or international projects, it may take several years to evaluate the future
potential of an exploration 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.
Due to our level of planned exploration activity, future dry hole cost could be material and have a negative impact on our
results of operations and cash flows.
Estimates of crude oil and natural gas reserves are not precise.
There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and their value, including factors that
are beyond our control. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and
natural gas that cannot be measured in an exact manner. In accordance with the SEC's rules for oil and gas reserves reporting,
our reserves estimates are based on 12-month average prices; therefore, reserves quantities will change when actual prices
increase or decrease. The 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 costs;
impacts of cost recovery provisions in contracts with foreign governments;
severance and excise taxes; and
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• workover and remedial costs.
For these reasons, estimates of the economically recoverable quantities of crude oil and natural gas 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 and natural gas reserves in emerging areas or areas with limited historical production,
such as onshore US shale areas and offshore areas such as ultra-deepwater Gulf of Mexico, the Eastern Mediterranean or West
Africa, 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, revenue and expenditures with respect to our reserves likely
will vary, possibly materially, from estimates.
Additionally, because some of our reserves estimates are calculated using volumetric analysis, those estimates are less reliable
than the estimates based on a lengthy production history. Volumetric analysis 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. In addition, realization or
recognition of proved undeveloped reserves will depend on our development schedule and plans. A change in future
development plans for proved undeveloped reserves could cause the discontinuation of the classification of these reserves as
proved. See Items 1. and 2. Business and Properties - Proved Reserves Disclosures.
We may be unable to make attractive acquisitions, successfully integrate acquired businesses and/or assets, or adjust to the
effects of divestitures, causing a disruption to our business.
One aspect of our business strategy calls for acquisitions of businesses and assets that complement or expand our current
business, such as our Marcellus Shale acquisition in 2011 and our DJ Basin asset acquisition in 2010. This may present greater
risks for us than those faced by peer companies that do not consider acquisitions as a part of their business strategy. We cannot
provide assurance that we will be able to identify attractive acquisition opportunities. Even if we do identify attractive
opportunities, we cannot provide assurance that we will be able to complete the acquisition due to capital market constraints,
even if such capital is available on commercially acceptable terms. If we acquire an additional business, we could have
difficulty integrating its operations, systems, management and other personnel and technology with our own, or could assume
unidentified or unforeseeable liabilities, resulting in a loss of value.
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We maintain an ongoing portfolio management program which includes sales of non-core, non-strategic assets, such as the
sales of certain non-core onshore US and North Sea assets in 2012. These transactions can also result in changes in operations,
systems, or management and other personnel.
Organizational modifications due to acquisitions, divestitures or other portfolio management actions, or other strategic changes
can alter the risk and control environments, disrupt ongoing business, distract management and employees, increase expenses
and adversely affect results of operations. Even if these challenges can be dealt with successfully, we cannot provide assurance
that the anticipated benefits of any acquisition, divestiture or other strategic change would be realized.
We may be unable to dispose of non-core, non-strategic assets on financially attractive terms, resulting in reduced cash proceeds
and/or losses.
We maintain an ongoing portfolio management program according to which we may divest non-core, non-strategic assets, such
as our sale of certain onshore US and North Sea assets in 2012. Asset divestitures can 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 include 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 other factors. 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 had expected.
We operate in a litigious environment.
We operate in the US and some other countries which have proven to be litigious environments. Most oil and gas companies,
such as us, are involved in various legal proceedings, such as title, royalty, or contractual disputes, in the ordinary course of
business. In addition, oil and gas companies are often the target of “legacy lawsuits”. A “legacy lawsuit” refers to a lawsuit by a
landowner claiming that oil and gas operations, often performed many years ago and by another operator, caused pollution or
contamination of a property. Claims against the current operator may be onerous while not allowing for cleanup at the site.
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. 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. Legal proceedings 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.
Failure to fund continued capital expenditures could adversely affect our properties.
Our exploration, development, and acquisition activities require substantial capital expenditures especially in the case of our
major development projects, such as the horizontal Niobrara and Marcellus Shale drilling programs, Gunflint, Alen, and Tamar.
Development of LNG terminals or underwater pipelines for export of gas from Leviathan will require a multi-billion dollar
investment. In addition, our CONSOL Carried Cost Obligation requires us to pay one-third of CONSOL's working interest
share of certain future drilling and completion costs, up to approximately $2.1 billion, generally during periods in which
average Henry Hub natural gas prices are above $4.00 per MMBtu. Major offshore projects have a long development cycle
time, which means that development spending occurs for several years before the project begins producing and generating cash
flows.
Historically, we have funded our capital expenditures through a combination of cash flows from operations, our revolving bank
credit facility, debt issuances, and occasional sales of non-strategic assets. Future cash flows from operations are subject to a
number of variables, such as the level of production from existing wells, prices of crude oil, natural gas and NGLs, and our
success in finding, developing and producing new reserves.
If revenues were to decrease as a result of lower crude oil, natural gas, or NGL prices or decreased production, and/or our
access to debt or capital were limited, we would have a reduced ability to replace our reserves, resulting in lower production
over time. If our cash flows from operations are not sufficient to meet our obligations and fund our capital investment program,
we may not be able to access capital markets on an economic basis to meet these requirements. If we are not able to fund our
capital expenditures, our ownership interests in some properties might be reduced or forfeited as a result. See Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations - 2013 Capital Investment Program.
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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 trade, joint venture, and other receivables. We sell our crude oil, natural gas and
NGLs to a variety of purchasers. In addition, we are the operator on a majority of our large joint venture development
projects. 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. For example our partners in the Eastern
Mediterranean must obtain financing for their share of significant development expenditures at Leviathan, which potentially
includes an LNG project and/or major underwater pipeline, and offshore Cyprus.
In addition, some of our purchasers and joint venture partners are not as creditworthy as we are and may experience credit
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 commodity sales or reimbursement of joint venture costs. Credit enhancements have
been obtained from some parties in the way of parental guarantees or letters of credit, including our largest crude oil purchaser;
however, not all of our trade credit is protected through guarantees or credit support. Nonperformance by a trade creditor or
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 conduct our hedging activities with a diverse group of investment grade major banks and
market participants, and we monitor and manage our level of financial exposure. 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. “Net
settlement” refers to a process by which all transactions between counterparties are resolved into a single amount owed by one
party to the other.
We had almost $1.4 billion in cash and cash equivalents at December 31, 2012, a majority of which was invested in money
market funds and short-term deposits with major financial institutions. We monitor the creditworthiness of the banks and
financial institutions with which we invest and review the securities underlying our investment accounts. However, we are
unable to predict sudden changes in solvency of our financial institutions.
We monitor the creditworthiness of our trade creditors, joint venture partners, hedging counterparties and financial institutions
on an ongoing basis. However, if one of them were to experience a sudden change 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 to perform.
Even if we do accurately predict sudden changes, our ability to negate the risk may be limited and we could incur significant
financial losses.
Commodity and interest rate hedging transactions may limit our potential gains.
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 crude oil and natural gas price hedging arrangements with respect to a portion of
our expected production. 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 crude oil and natural gas prices rise over the price established by the arrangements.
Global commodity prices fluctuated significantly in 2012. 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. In addition, hedging transactions may 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 the delivery point 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.
We use interest rate derivative instruments to minimize the impact of interest rate fluctuations associated with anticipated debt
issuances. Interest rates are variable and we may also end up hedging too much or too little when we attempt to effectively fix
cash flows related to interest payments on an anticipated debt issuance.
We have significant international operations and may enter into foreign currency derivative instruments in the future. Currency
exchange rates are variable and we may also end up hedging too much or too little when we attempt to mitigate our foreign
currency exchange risk.
We cannot assure that our hedging transactions will reduce the risk or minimize the effect of volatility in crude oil or natural
gas prices, interest rates, or exchange rates. See Item 8. Financial Statements and Supplementary Data - Note 10. Derivative
Instruments and Hedging Activities.
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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 and other unfortuitous
events such as blowouts, well cratering, fire and explosion and loss of well control which can result in damage to or destruction
of wells 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,
expropriation or nationalization of assets, which can cause loss of or damage to our property.
As is customary with industry practices, we maintain insurance against many, but not all, potential perils confronting our
operations and in coverage amounts and deductible levels that we believe to be economic. Consistent with that profile, our
insurance program is structured to provide us financial protection from unfavorable loss severity 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, at a level that balances cost
of insurance with our assessment of risk and our ability to achieve a reasonable rate of return on our investments. Although we
believe the coverages and amounts of insurance carried are adequate and consistent with industry practice, we do not have
insurance protection against all the risks we face, because we chose 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 exceed coverage limits. We regularly
review our risks of loss and the cost and availability of insurance and revise our insurance program accordingly.
We expect the future availability and cost of insurance to be impacted by such events as Hurricane Sandy in 2012, the 2011
earthquake and subsequent tsunami in Japan, and the 2010 Deepwater Horizon Incident. 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 the
legislative and regulatory response to the Deepwater Horizon Incident and its 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 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 Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations - Risk and Insurance Program.
We are subject to increasing governmental regulations and environmental requirements that may cause us to incur
substantial incremental costs.
From time to time, in varying degrees, political developments and international, federal and state laws and regulations affect
our operations. In particular, price controls, taxes and other laws relating to the crude oil and natural gas industry, changes in
these laws and changes in administrative regulations have affected and in the future could affect crude oil and natural gas
production, operations and economics. We cannot predict how agencies or courts will interpret existing laws and regulations or
the effect these adoptions and interpretations may have on our business or financial condition.
Our business is subject to laws and regulations promulgated by international, federal, state and local authorities relating to the
exploration for, and the development, production and marketing of, crude oil and natural gas, as well as safety matters. Legal
requirements are frequently changed and subject to interpretation and we are unable to predict the ultimate cost of compliance
with these requirements or their effect on our operations. We may be required to make substantial expenditures to comply with
governmental laws and regulations.
Our operations are subject to complex international, federal, state and local environmental laws and regulations including, for
example, in the case of federal laws, the Comprehensive Environmental Response, Compensation and Liability Act, as
amended, the Resource Conservation and Recovery Act, as amended, the Oil Pollution Act of 1990, the Clean Air Act, the
Clean Water Act, the Endangered Species Act, the Safe Drinking Water Act, and the Occupational Safety and Health Act.
Environmental laws and regulations change frequently and the implementation of new, or the modification of existing, laws or
regulations could negatively impact our operations. The discharge of natural gas, crude oil, or other pollutants into the air, soil
or water may give rise to substantial liabilities on our part to government agencies and third parties and may require us to incur
substantial costs of remediation. In addition, we may incur costs and penalties in addressing regulatory agency procedures
involving instances of possible non-compliance. See Items 1. and 2. Business and Properties - Regulations.
A change in US energy policy can have a significant impact on our operations and profitability.
US energy policy and laws and regulations could change quickly, and substantial uncertainty exists about the nature of many
potential rules and regulations that could impact the sources and uses of energy in the US. For example, new Corporate
Average Fuel Economy (CAFE) standards enacted in 2012 will result in a rapid increase in the fuel economy of cars and light
trucks and could potentially have both a negative impact on demand for crude oil and a positive impact on demand for natural
gas for road transport use. GHG emissions regulations could increase the demand for natural gas as fuel for power generation.
54
We design our exploration and development strategy and related capital investment programs years in advance. As a result, we
are hindered in our ability to plan, invest and respond to potential changes in our business. This can result in a reduction of our
cash flows and profitability to the extent we are unable to respond to sudden or significant changes in our operating
environment due to changes in US energy policy.
The unavailability or high cost of drilling rigs, equipment, supplies, other oil field services and personnel 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, from time to time, there is a shortage of drilling rigs, equipment, supplies and oilfield services.
There may also be a shortage of trained and experienced personnel. During these periods, the costs of such items are
substantially greater and their availability may be limited, particularly in areas of high activity and demand in which we
concentrate, such as the DJ Basin, Marcellus Shale, deepwater Gulf of Mexico, and in some international locations that
typically have limited availability of equipment and personnel, such as West Africa and the Eastern Mediterranean.
During periods of increasing levels of industry exploration and production, such as is occurring in the DJ Basin and Marcellus
Shale, the demand for, and cost of, drilling rigs and oilfield services increases. The recovery of global crude oil prices during
2011 has resulted in increased exploration and production activity, thus increasing demand pressure for drilling rigs and oilfield
services, which could result in sector inflation. In addition, regulatory changes, such as in response to the Deepwater Horizon
Incident or related to hydraulic fracturing, may also result in reduced availability and/or higher costs for these 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.
See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Contractual
Obligations.
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.
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 ability to successfully and economically explore for and develop crude oil and natural gas resources;
anticipated trends in our business;
our future results of operations;
our liquidity and ability to finance our exploration, development, and acquisition activities;
•
•
•
•
•
• market conditions in the oil and gas industry;
our ability to make and integrate acquisitions;
•
the impact of governmental fiscal terms and/or regulation, such as that involving the protection of the environment or
•
marketing of production, as well as other regulations; 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.
Item1B. Unresolved Staff Comments
None.
55
Item 3. Legal Proceedings
See Item 8. Financial Statements and Supplementary Data – Note 20. Commitments and Contingencies.
Item 4. Mine Safety Disclosures
Not Applicable.
Executive Officers
The following table sets forth certain information, as of February 7, 2013, with respect to our executive officers.
Name
Charles D. Davidson (1)
Age
62
Chairman of the Board, Chief Executive Officer and Director
Position
David L. Stover (2)
Kenneth M. Fisher (3)
Ted D. Brown (4)
Rodney D. Cook (5)
55
President, Chief Operating Officer
51
Senior Vice President, Chief Financial Officer
57
Senior Vice President, Northern Region
55
Senior Vice President, International
Susan M. Cunningham (6)
57
Senior Vice President, Exploration
Arnold J. Johnson (7)
57
Senior Vice President, General Counsel and Secretary
Andrea Lee Robison (8)
54
Vice President, Human Resources and Administration
(1) Charles D. Davidson was elected Chief Executive Officer of Noble Energy in October 2000 and Chairman of the Board in April 2001,
also serving as President until April 2009 (at which time Mr. Stover assumed that position). Prior to October 2000, he served as
President and Chief Executive Officer of Vastar Resources, Inc. from March 1997 to September 2000 (Chairman from April 2000) and
was a Vastar Director from March 1994 to September 2000. From September 1993 to March 1997, he served as a Senior Vice President
of Vastar. From 1972 to October 1993, he held various positions with ARCO.
(2) David L. Stover was elected President and Chief Operating Officer of Noble Energy in April 2009. Prior thereto, he served as Executive
Vice President and Chief Operating Officer of Noble Energy from August 2006 to April 2009. He served as Senior Vice President of
North America and Business Development from July 2004 through July 2006, and he served as Noble Energy’s Vice President of
Business Development from December 2002 through June 2004. Previous to his employment with Noble Energy, he was employed by
BP America, Inc. as Vice President, Gulf of Mexico Shelf from September 2000 to August 2002. Prior to joining BP, Mr. Stover was
employed by Vastar, as Area Manager for Gulf of Mexico Shelf from April 1999 to September 2000, and prior thereto, as Area Manager
for Oklahoma/Arklatex from January 1994 to April 1999. From 1979 to 1994, he held various positions with ARCO.
(3) Kenneth M. Fisher was elected Senior Vice President and Chief Financial Officer of Noble Energy in November 2009. Prior to joining
Noble Energy, Mr. Fisher served as Executive Vice President of Finance for Upstream Americas for Shell from July 2009 to November
2009. Prior to his most recent position with Shell, Mr. Fisher served as Director of Strategy & Business Development for Royal Dutch
Shell plc in The Hague from August 2007 to July 2009. He served as Executive Vice President of Strategy & Portfolio for Shell’s
downstream business in London from January 2005 to August 2007. Mr. Fisher joined Shell in August 2002 and served as Chief
Financial Officer for Shell Oil Products U.S. until December 2004. As Chief Financial Officer for Shell Oil Products U.S., he was
responsible for U.S. oil products finance, information technology and contracting and procurement activities. Prior to joining Shell, he
held positions of increasing responsibility with General Electric Company (GE) from 1984 to 2002, including Vice President and Chief
Financial Officer of the Aircraft Engines Services division and Director of Finance & Business Development of GE’s Asia Pacific
plastics business.
56
(4) Ted D. Brown was elected a Senior Vice President of Noble Energy in April 2008 and is currently responsible for the Northern Region of
our North America division. He served as Vice President, responsible for the same region, from August 2006 to April 2008 and as a vice
president of that division since joining Noble Energy upon our acquisition of Patina Oil & Gas Corporation (Patina) in May 2005. He
served as Senior Vice President of Patina from July 2004 to May 2005. Prior thereto he served as Director, Piceance Basin Asset along
with Engineering Manager for Williams and Barrett Resources since 1993 and, before that, in various positions with Union Pacific
Resources and Amoco Production Company.
(5) Rodney D. Cook was elected a Senior Vice President of Noble Energy in April 2008 and is currently responsible for the International
division. He served as Vice President of Noble Energy, responsible for the Southern Region of our North America division, from August
2006 to April 2008 and as a vice president of that division from May 2005 to August 2006. He served as Manager of our West Africa and
Middle East Business Unit from 2002 to 2005. Prior thereto he served as Operations Manager of the International division since 1996.
From 1980 to 1996 he held various positions with Noble Energy. Prior to joining Noble Energy in 1980, Mr. Cook held various positions
with Texas Pacific Oil.
(6) Susan M. Cunningham was elected a Senior Vice President of Noble Energy in April 2001 and is currently responsible for our world-
wide exploration. Prior to joining Noble Energy, Ms. Cunningham was Texaco’s Vice President of worldwide exploration from April
2000 to March 2001. From 1997 through 1999, she was employed by Statoil, beginning in 1997 as Exploration Manager for deepwater
Gulf of Mexico, appointed a Vice President in 1998 and responsible, in 1999, for Statoil’s West Africa exploration efforts. She joined
Amoco Canada in 1980 as a geologist and held various exploration and development positions with Amoco Production Company until
1997.
(7) Arnold J. Johnson was elected Senior Vice President, General Counsel and Secretary of Noble Energy in July 2008. Prior thereto, he
served as Vice President, General Counsel and Secretary of Noble Energy since February 2004. He served as Associate General Counsel
and Assistant Secretary of Noble Energy from January 2001 through January 2004. Previous to his employment with Noble Energy, he
served as Senior Counsel for BP America, Inc. from October 2000 to January 2001. Mr. Johnson held several positions as an attorney for
Vastar and ARCO from March 1989 through September 2000, most recently as Assistant General Counsel and Assistant Secretary of
Vastar from 1997 through 2000. From 1980 to March 1989, he held various positions with ARCO.
(8) Andrea Lee Robison was elected a Vice President of Noble Energy in November 2007 and is responsible for Human Resources and
Administration. Prior thereto, she served as Director of Human Resources from May 2002 through October 2007. Prior to joining us,
Ms. Robison was Manager of Human Resources for the Gulf of Mexico Shelf for BP America, Inc. from September 2000 through April
2002. Prior to her employment at BP, she served as HR Director at Vastar from 1997 through September 2000, and Compensation
Consultant from January 1994 through 1996. From 1980 through 1993, she held various positions with ARCO.
57
PART II
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 are at the discretion of our Board of Directors 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:
2011
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
2012
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
High
Low
Dividends
Per Share
$
$
$
$
98.99
98.72
101.27
99.17
105.46
100.98
97.60
103.08
$
$
81.27
82.50
69.25
65.91
93.57
76.83
82.33
90.00
0.18
0.18
0.22
0.22
0.22
0.22
0.22
0.25
On January 28, 2013, the Board of Directors declared a quarterly cash dividend of $0.25 per common share, which will be paid
February 25, 2013 to shareholders of record on February 11, 2013.
Transfer Agent and Registrar The transfer agent and registrar for our common stock is Wells Fargo Bank, N.A., 161 North
Concord Exchange, South St. Paul, MN, 55075.
Stockholders’ Profile Pursuant to the records of the transfer agent, as of January 18, 2013, the number of holders of record of
our common stock was 635.
Stock Repurchases The following table summarizes repurchases of our common stock occurring fourth quarter 2012.
Period
10/1/2012 - 10/31/12
11/1/2012 - 11/30/12
12/1/2012 - 12/31/12
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)
839
$
6,726
601
8,166
$
94.47
92.48
99.77
93.22
—
—
—
—
—
—
—
—
(1)
Stock repurchases during the period related to stock received by us from employees for the payment of withholding taxes due on shares
issued under stock-based compensation plans.
58
Equity Compensation Plan Information The following table summarizes information regarding the number of shares of our
common stock that are available for issuance under all of our existing equity compensation plans as of December 31, 2012.
Plan Category
Equity Compensation Plans Approved by
Security Holders
Equity Compensation Plans Not
Approved by Security Holders
Total
Number of Securities
to be Issued Upon
Exercise of
Outstanding Options,
Warrants and Rights
(a)
Weighted Average
Exercise Price of
Outstanding
Options,
Warrants and Rights
(b)
Number of Securities
Remaining Available for
Future Issuance Under
Equity Compensation Plans
(Excluding Securities
Reflected in Column (a))
(c)
6,205,786
$
—
6,205,786
$
70.27
—
70.27
7,486,668
—
7,486,668
Stock Performance Graph This graph shows our cumulative total shareholder return over the five-year period from December
31, 2007 to December 31, 2012. The graph also shows the cumulative total returns for the same five-year period of the S&P 500
Index, an old peer group of companies and a new peer group of companies. The cumulative total return of the common stock of
our old and new peer groups of companies includes the cumulative total return of our common stock.
The companies in the old peer group consisted of the following:
Anadarko Petroleum Corp.
Apache Corp.
Cabot Oil & Gas Corp.
Chesapeake Energy Corp.
Devon Energy Corp.
EOG Resources, Inc.
Forest Oil Corp.
Murphy Oil Corp.
Newfield Exploration Company
Noble Energy, Inc.
Pioneer Natural Resources Company
Plains Exploration and Production Company
Range Resources Corp.
Southwestern Energy Company
Talisman Energy Inc.
On January 23, 2012, the Compensation, Benefits and Stock Option Committee of the Board of Directors (the Committee)
made changes to our compensation peer group to remove Forest Oil Corp. and Talisman Energy Inc. from the old peer group
listed above given their growing dissimilarity to our operational and financial characteristics, and add Marathon Oil
Corporation and Continental Resources, Inc., which are US companies listed on the NYSE with a balance of projects similar in
size and scope to ours. After the change in companies, the 2012 compensation peer group consisted of the following:
Anadarko Petroleum Corp.
Apache Corp.
Cabot Oil & Gas Corp.
Chesapeake Energy Corp.
Continental Resources, Inc.
Devon Energy Corp.
EOG Resources, Inc.
Marathon Oil Corporation
Murphy Oil Corp.
Newfield Exploration Company
Noble Energy, Inc.
Pioneer Natural Resources Company
Plains Exploration and Production Company
Range Resources Corp.
Southwestern Energy Company
59
The comparison assumes $100 was invested on December 31, 2007 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
Year Ended December 31,
Noble Energy, Inc.
S&P 500
Old Peer Group
New Peer Group
2007
2008
2009
2010
2011
2012
$
$
100.00
100.00
100.00
100.00
$
62.51
63.00
62.91
61.52
$
91.55
79.67
93.30
88.30
$
111.73
91.67
105.49
100.19
$
123.62
93.61
93.57
97.29
134.52
108.59
93.54
99.08
60
Item 6. Selected Financial Data
(millions, except as noted)
Revenues and Income (Loss)
Total Revenues
Income (Loss) from Continuing Operations
Net Income (Loss)
Per Share Data
Earnings (Loss) Per Share - Basic
Income (Loss) from Continuing Operations
Net Income (Loss)
Earnings (Loss) Per Share - Diluted
Income (Loss) from Continuing Operations
Net Income (Loss)
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
Acquisitions
Proceeds from Divestitures
Financial Position
Cash and Cash Equivalents
Commodity Derivative Instruments - Current
Property, Plant, and Equipment, Net
Goodwill
Total Assets
Long-term Obligations
Long-Term Debt
Deferred Income Taxes
Commodity Derivative Instruments
Asset Retirement Obligations
Other
Shareholders' Equity
Operations Information - Consolidated Operations
Consolidated Crude Oil Sales (MBbl/d)
Average Realized Price ($/Bbl) (1)
Consolidated Natural Gas Sales (MMcf/d)
Average Realized Price ($/Mcf) (1)
Consolidated NGL Sales (MBbl/d)
Average Realized Price ($/Bbl)
Proved Reserves
Crude Oil, Condensate and NGL Reserves (MMBbls)
Natural Gas Reserves (Bcf)
Total Reserves (MMBoe)
Number of Employees
Year Ended December 31,
2012
2011
2010
2009
2008
$
$
$
$
$
$
$
$
$
$
$
$
$
$
4,223
965
1,027
5.43
5.77
5.37
5.71
0.91
101.74
178
180
2,933
3,650
—
1,160
1,387
63
13,551
635
17,554
3,736
2,218
3
333
474
8,258
86
101.52
774
2.19
16
35.36
357
4,964
1,184
2,190
$
$
$
$
$
$
$
3,404
412
453
2.34
2.57
2.31
2.54
0.80
94.39
176
179
2,170
2,594
527
77
1,455
10
12,782
696
16,444
4,100
2,059
7
344
401
7,265
56
99.17
806
3.00
15
48.35
369
5,043
1,209
1,876
$
$
$
$
$
$
$
2,713
631
725
3.61
4.15
3.56
4.10
0.72
86.08
175
177
1,946
1,885
458
564
1,081
62
10,264
696
13,282
2,272
2,110
51
208
371
6,848
54
75.76
781
2.98
14
41.21
365
4,361
1,092
1,772
$
2,160
(159)
(131)
(0.92) $
(0.75)
(0.92)
(0.75)
0.72
71.22
173
173
1,508
1,268
—
3
1,014
13
8,916
758
11,807
2,037
2,076
17
181
349
6,157
55
55.32
776
2.52
10
27.96
336
2,904
820
1,630
$
$
$
$
$
3,491
1,204
1,350
6.98
7.83
6.75
7.58
0.66
49.22
173
176
2,285
1,971
292
131
1,140
437
9,004
759
12,384
2,241
2,174
2
184
300
6,309
59
79.38
762
5.00
9
50.15
311
3,315
864
1,571
(1) Prices through 2010 include effects of oil and gas hedging activities. See Item 8. Financial Statements and Supplementary Data –
Note 10. Derivative Instruments and Hedging Activities.
61
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 Overview;
• Operating Outlook;
• Results of Operations;
•
Proved Reserves;
• 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 OVERVIEW
Strategy We are a worldwide producer of crude oil and natural gas. We aim to achieve sustainable growth in value and cash flow
through exploration success and the development of a high-quality, diversified, growing portfolio of assets that is balanced between
US and international projects, while maintaining a strong balance sheet and ample liquidity levels. We primarily focus on organic
growth from exploration and development drilling and augment that with a periodic, opportunistic new business development
(mergers and acquisition) capability. We manage the portfolio for superior returns and to ensure geographic portfolio diversification,
with periodic divestments of non-core assets. We focus on basins or plays where we have strategic competitive advantage and
which we believe generate superior returns.
Core operating areas are the onshore US (DJ Basin and Marcellus Shale), deepwater Gulf of Mexico, offshore West Africa and
offshore Eastern Mediterranean. As a result of our continued exploration success, we are focused on the execution of a
significant portfolio of major development projects that will deliver visible growth including, among others: the horizontal
Niobrara in the DJ Basin and the Marcellus Shale, onshore US; Gunflint and Big Bend in the deepwater Gulf of Mexico; Tamar
and Leviathan, offshore Israel; offshore Cyprus; Alen, Carla, and Diega, offshore West Africa.
Our major development projects typically offer long life, sustained cash flows after investment and attractive financial returns.
We maintain a diversified portfolio between US and international assets and strive to maintain a balanced geographic and
political risk profile. We also maintain a geographical diversity of production mix among crude oil, US natural gas, and
international natural gas.
Current Business and Industry Environment The global economy continued its recovery during 2012. Although there was
modest growth in the US, China and emerging markets, Europe continued to struggle with its debt crisis. In the US, uncertainty
continues to surround resolution of federal deficit issues. It is difficult to predict the economic consequences on global markets
as governments attempt to resolve these issues.
In the global crude oil market, supplies grew, primarily due to the application of horizontal drilling technology to liquids plays
and increasing supplies from unconventional sources (oil from tight formations and oil sands) in the US and Canada. Prices
remained strong, supported by modest demand growth and continued security and other threats to the global crude oil supply
system. Brent prices remain at a premium to WTI primarily due to transportation constraints in the US Mid-Continent area
which impact WTI netbacks.
In the US, the application of horizontal drilling technology has significantly changed the natural gas markets, resulting in an
oversupply of natural gas and considerably lower Henry Hub spot and forward prices. Increased drilling in liquids-rich gas
areas and increased associated gas production from oil plays has yielded significant growth in onshore US NGL production. As
a result, the NGL market softened during 2012, and NGL prices declined.
Despite the uncertainty surrounding the global economy and continued volatility in commodity prices, we believe our portfolio
positions us well moving forward. We have material new production onshore US and offshore Equatorial Guinea, substantial
liquidity and cash flow, a solid balance sheet, and a line-up of major development projects which we expect to contribute to
future growth.
62
2012 Results Noble Energy delivered significant growth in 2012. Expansion of our horizontal Niobrara and Marcellus Shale
developments resulted in a 24% increase in Wattenberg production and a four fold increase in Marcellus Shale production. We
realized further production increases from major new developments at Aseng, offshore Equatorial Guinea, and Galapagos,
deepwater Gulf of Mexico, that came on line in 2011 and 2012, respectively. We moved forward on our major development
projects, each of which will yield significant new production in future years, discovered new resources at Big Bend in the
deepwater Gulf of Mexico and Carla, offshore Equatorial Guinea, and farmed into new opportunities offshore the Falkland
Islands and Sierra Leone. Finally, we enhanced our portfolio with selective divestitures of non-core, onshore US and North Sea
properties, and maintained our strong balance sheet.
Our 2012 financial results included:
•
•
•
•
•
•
•
•
•
•
•
•
•
net income over $1.0 billion (including $965 million from continuing operations) as compared with $453 million
(including $412 million from continuing operations) for 2011 ;
dry hole cost of $155 million, as compared with $105 million for 2011;
gain on divestitures of $154 million as compared with $25 million for 2011;
asset impairment charges of $104 million as compared with $757 million for 2011;
gain on commodity derivative instruments of $75 million (including unrealized mark-to-market gain of $109 million) as
compared with $42 million gain on commodity derivative instruments (including unrealized mark-to-market loss of $22
million) for 2011;
diluted earnings per share of $5.71, as compared with $2.54 for 2011;
cash flows provided by operating activities of $2.9 billion, as compared with $2.2 billion in 2011;
received $1.2 billion in proceeds from divestments of non-core assets, as compared with $77 million in 2011;
capital spending on a cash basis of $3.7 billion as compared with $3.1 billion in 2011 (including $527 million for the
Marcellus Shale asset acquisition);
exercised option to increase credit facility from $3.0 billion to $4.0 billion, enhancing our liquidity position;
ending cash and cash equivalents balance of $1.4 billion at December 31, 2012, as compared with $1.5 billion at
December 31, 2011;
total liquidity of $5.4 billion at December 31, 2012, consisting of year-end cash balance plus funds available under our
credit facility, as compared with $4.5 billion at December 31, 2011; and
year-end ratio of debt-to-book capital of 33%, as compared with 38% at December 31, 2011.
Significant operational highlights for 2012 included the following:
Overall
•
•
•
total sales volumes from continuing operations of 239 MBoe/d, a 12% increase as compared with 2011;
liquids represent 46% of total sales volumes from continuing operations as compared to 37% in 2011; and
year-end proved reserves of 1.2 BBoe, a decrease of 2% from year-end 2011.
Onshore United States
•
•
•
increased DJ Basin (Wattenberg) total sales volumes to 77 MBoe/d, net, with horizontal production contributing 28
MBoe/d, net;
spud 200 and completed 193 horizontal wells in the DJ Basin;
expanded the Northern Colorado acreage position by 26,000 net acres to 230,000 net acres, where recent horizontal
Niobrara results indicate recoveries comparable to Wattenberg;
• Marcellus Shale production grew to 92 MMcfe/d, net, as compared with 19 MMcfe/d, net, in 2011;
•
drilled to total depth 89 and completed 71 gross horizontal wells in the Marcellus Shale and initiated production from
the wet gas area;
experienced higher recovery rates than anticipated in the DJ Basin and Marcellus Shale;
entered new exploration area in Northeast Nevada; and
completed non-core onshore asset dispositions.
•
•
•
Deepwater Gulf of Mexico
announced a discovery at the Big Bend prospect;
•
• Galapagos produced at an average rate of 6 MBbl/d of crude oil, net; and
•
acquired six deepwater Gulf of Mexico blocks at the Outer-Continental Shelf Sale 222.
63
International
discovery of a new crude oil reservoir at Carla, offshore Equatorial Guinea;
•
• Aseng field, offshore Equatorial Guinea, produced at an average gross rate of 62 MBbl/d of crude oil (21 MBbl/d,
net);
acceleration of Alen development, offshore Equatorial Guinea;
installed the Tamar platform and initiated the commissioning process;
announced a strategic development partner for the Leviathan project, offshore Israel;
announced the Tanin natural gas discovery, offshore Israel;
entered into new positions offshore Falkland Islands and Sierra Leone;
secured contract with new-build drillship capable of reaching deep oil targets in the Eastern Mediterranean; and
completed the sale of our Dumbarton and Lochranza assets in the North Sea.
•
•
•
•
•
•
•
Acquisitions and Divestitures
Strategic Partner for Leviathan The Leviathan field, offshore Israel, is the largest conventional natural gas discovery in our
history, with resources available for both domestic and export markets. During 2012, we and our existing partners in the Leviathan
project commenced a process to identify a partner who could provide technical and financial support as well as midstream and
downstream expertise. On December 2, 2012, we and our existing partners announced that we had agreed in principle on a proposal
to sell a 30% working interest in the Leviathan licenses to Woodside Energy Ltd. (Woodside). Woodside is Australia's largest
producer of LNG with over 25 years of experience and has strong working relationships with many potential customers in the
Asian LNG markets. We expect to execute a final agreement with Woodside during the first half of 2013.
2012 Non-Core Divestiture Program Our non-core divestiture program is designed to generate organizational and operational
efficiencies as well as cash for use in our capital investment program. Divestitures of non-core properties allow us to allocate
capital and employee resources to high-value and high-growth areas. Further, proceeds from divestitures provide additional
flexibility in the implementation of our international exploration and development programs and the acceleration of horizontal
drilling activities in the DJ Basin and Marcellus Shale. During 2012, divestitures generated net proceeds of approximately $1.2
billion.
On August 13, 2012, we closed the sale of our 30% non-operated working interest in the Dumbarton and Lochranza fields,
located in the UK sector of the North Sea. Proceeds from the transaction were $117 million, and included final closing
adjustments from the effective date of January 1, 2012. The net book value of assets sold was $255 million. We reversed a
deferred tax liability and recognized a corresponding income tax benefit of $99 million related to the sale. Net daily production
was approximately 5 MBoe/d at the time of the sale.
During third quarter 2012, we closed on three sales of onshore US properties in Kansas, western Oklahoma, western Texas, and
the Texas Panhandle for total proceeds of $1.0 billion. The properties included our interests in about 1,400 producing wells on
approximately 109,000 net acres. As of the effective date, April 1, 2012, net daily production was approximately 12.5 MBoe/d.
Additionally, we are continuing the process of marketing certain non-core onshore US properties and are currently soliciting
bids. As of December 31, 2012, the Board of Directors and management had not committed to any specific plans to sell the
assets, individually or as packaged groups. Therefore, none of these assets was reclassified as held-for-sale at December 31,
2012.
2012 Entry into Falkland Islands Joint Venture In August 2012, we entered into an agreement with Falkland Oil and Gas
Limited (FOGL) and subsequently acquired an interest in FOGL's extensive license areas consisting of approximately 10
million undeveloped acres, gross, located south and east of the Falkland Islands.
2012 Entry into Sierra Leone In September 2012, the Government of Sierra Leone awarded us participation in two offshore
exploration blocks, SL 8A-10 and SL 8B-10, covering almost 1.4 million acres, gross. Under the terms of the award, Chevron
(SL) Ltd. will be the operator and we will have a non-operated 30% working interest.
2012 Exit from Senegal/Guinea-Bissau We decided not to participate in additional appraisal activities and relinquished our
acreage.
2011 Entry into Marcellus Shale Joint Venture On September 30, 2011, we entered an agreement with CONSOL to jointly
develop oil and gas assets in the Marcellus Shale areas of southwest Pennsylvania and northwest West Virginia. The Marcellus
Shale joint venture strengthened and rebalanced our portfolio, providing a new, material growth area, which has contributed to
reserves and production growth and provides balance to our rapidly expanding international programs.
2011 Ecuador Exit In May 2011, we transferred our assets in Ecuador to the Ecuadorian government, receiving cash proceeds of
$73 million. The net book value of the assets had been reduced due to previous impairment charges, resulting in a pre-tax gain of
$25 million.
64
2010 DJ Basin Asset Acquisition In March 2010, we acquired substantially all of the US Rocky Mountain assets of Petro-
Canada Resources (USA) Inc. and Suncor Energy (Natural Gas) America Inc. for a total purchase price of $498 million. The
acquisition added approximately 46 MMBoe of proved reserves at closing date, and approximately 10 MBoe/d to our daily
production base, starting from the closing date. Included in the purchase were 323,000 total net acres, nearly 183,000 of which
are located in the DJ Basin.
2010 Onshore US Sale In August 2010, we closed the sale of non-core assets in the Mid-Continent and Illinois Basin areas for
cash proceeds of $552 million and recorded a gain of $110 million. The sale included approximately 32 MMBoe of proved
reserves, at closing date, and approximately 5.7 MBoe/d of production.
See Item 8. Financial Statements and Supplementary Data – Note 3. Acquisitions and Divestitures and Note 12. Long-Term Debt.
Sales Volumes
On a BOE basis, total sales volumes from continuing operations were 12% higher in 2012 as compared with 2011, and our mix
of sales volumes in 2012 was 46% global liquids, 23% international natural gas, and 31% US natural gas. Onshore US sales
volumes increased due to continued acceleration of our horizontal drilling programs in Wattenberg and the Marcellus Shale
program, which began at the end of the third quarter of 2011. In the deepwater Gulf of Mexico, new production from
Galapagos and South Raton contributed to the increase in sales volumes. International crude oil sales volumes were higher in
Equatorial Guinea due to the commencement of crude oil production at Aseng in the fourth quarter of 2011. Israel natural gas
sales volumes were lower as we have reduced the rate of production from the Mari-B field in order to manage the reservoir. See
Results of Operations – Revenues below.
Commodity Price Changes and Hedging
Historically, crude oil, natural gas and NGL prices have exhibited significant volatility. The crude oil market remained relatively
robust during 2012, benefiting from continued threats to the global crude oil supply system. Total consolidated average realized
crude oil prices for 2012 increased 2% as compared with 2011.
The domestic natural gas market remains weak, primarily due to an abundant supply and higher levels of gas in storage. US
average realized natural gas prices for 2012 decreased 33% as compared with 2011.
Prices continue to be impacted by the slowdown in the global economic recovery, influenced by uncertainty over the eurozone
debt crisis, and an increase in supply. As long as development activity continues at, or near, the current level and there is no
significant increase in demand, downward pressure on commodity prices is likely to continue. See Item 6. Selected Financial Data
for average realized prices for 2008 - 2012. See also Operating Outlook - Potential for Future Asset Impairments, below.
To enhance the predictability of our cash flows and support our capital investment program, we have hedged a portion of our
expected global crude oil and natural gas production for 2013. We use mark-to-market accounting for our commodity
derivative instruments and recognize all gains and losses on such instruments in earnings in the period in which they occur.
Derivative gains and losses included in net income include both pre-tax realized gains and losses and pre-tax, unrealized, non-
cash gains or losses which are due to the change in the mark-to-market value of our commodity contracts related to production
in future periods. Unrealized mark-to-market gains or losses recognized in the current period will be realized in the future when
they are cash settled in the month that the related production occurs. The amount of gain or loss actually realized may be more
or less than the amount of unrealized mark-to-market gain or loss previously reported. The use of mark-to-market accounting
adds volatility to our net income. See Item 8. Financial Statements and Supplementary Data – Note 10. Derivative Instruments
and Hedging Activities.
Asset Impairment Charges During 2012, we recorded impairment charges of $104 million, related to our South Raton and
Piceance developments due to near-term declines in crude oil and natural gas prices, respectively, and our Mari-B, Pinnacles
and Noa fields, offshore Israel, due to end-of-field life declines in production. See Item 8. Financial Statements and
Supplementary Data – Note 4. Asset Impairments.
OPERATING OUTLOOK
2013 Outlook We continue to monitor the outlook for the global economy and numerous critical factors including the US
federal budget deficit and long-term fiscal situation, the European debt crisis and their potential impacts on global economic
growth and commodity prices. We expect the overall global economy to continue a pattern of modest growth, while the
European economy is likely to continue to struggle with low growth resulting from its debt crisis.
65
We expect global crude oil production volumes to continue to grow, primarily due to increases in the US and Canada from
continued application of horizontal drilling technology. This growth will likely result in an increase in OPEC spare production
capacity. Meanwhile, political risk remains strong: North African and Mideast conflicts, civil unrest, and other potential supply
interruption risks are likely to continue. Global crude oil demand is expected to grow in 2013 as the global economy continues
to grow. Global crude oil prices will be determined by these supply and demand factors. In the US, de-bottlenecking in the
Mid-Continent as transportation improves will also increase Gulf Coast supply; as a result, we expect that US prices will
continue to trade at a discount to Brent.
In the US, we expect natural gas prices to be range-bound, as production has continued to increase, even with lower rig counts,
until new demand sources catch up with supply growth. One significant issue potentially impacting the industry is the amount
of US natural gas exports via LNG that will be approved by the DOE.
Because the global economic outlook and commodity price environment are uncertain, we have built a strong liquidity position
to ensure financial flexibility and planned a flexible capital spending program which will support both major project
development and exploration activities in a volatile commodity price environment. See 2013 Capital Investment Program
below.
2013 Production Our expected crude oil, natural gas and NGL production for 2013 may be impacted by several factors
including:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
overall level and timing of capital expenditures which, as discussed below and dependent upon our drilling success, are
expected to maintain our near-term production volumes;
timing of major development project completion and initial production, including Tamar, offshore Israel, and Alen,
offshore Equatorial Guinea, which are scheduled to begin producing in 2013;
ongoing development activity in the Wattenberg area and horizontal drilling in the Niobrara formation in the DJ Basin;
pace of increase of development activity in both wet gas and dry gas areas of the Marcellus Shale;
divestments of non-core operating assets;
natural field decline in the deepwater Gulf of Mexico, Gulf Coast and Mid-Continent areas of our US operations, and the
Mari-B field in Israel (See Items 1. and 2. Business and Properties - Delivery Commitments);
variations in sales volumes of natural gas from the Alba field in Equatorial Guinea related to potential downtime at the
methanol, LPG and/or LNG plants;
Israeli demand for electricity which affects demand for natural gas as fuel for power generation, market growth,
production rates from the Mari-B, Noa and Pinnacles wells, and anticipated production from Tamar, offshore Israel;
variations in West Africa sales volumes due to potential FPSO downtime and timing of liftings;
potential hurricane-related volume curtailments in the deepwater Gulf of Mexico and Gulf Coast areas;
potential winter storm-related volume curtailments in the Rocky Mountain and/or Marcellus Shale areas of our US
operations;
third party facilities reliability in the Wattenberg and/or Rocky Mountain areas of our US properties which may cause
restrictions or interruptions in mid-stream processing facilities;
potential pipeline and processing facility capacity constraints in the Rocky Mountain and/or Marcellus Shale areas of our
US operations;
potential drilling and/or hydraulic fracturing permit delays due to future regulatory changes;
potential purchases of producing properties; and
potential shut-in of US producing properties if storage capacity becomes unavailable.
2013 Capital Investment Program Our total capital investment program for 2013 is estimated at $3.9 billion. The capital
investment program allocates approximately 60% to onshore US, 6% for deepwater Gulf of Mexico, 10% to the Eastern
Mediterranean, 15% to West Africa and 9% to corporate and other. Exploration and appraisal activity within these geographic
areas is expected to receive 15% of total capital.
The 2013 capital investment program will exceed operating cash flows and is expected to be funded from cash flows from
operations, cash on hand, and borrowings under our revolving credit facility and/or other financing such as an issuance of long-
term debt. Funding may also be provided by proceeds from divestment of non-core assets. See Liquidity and Capital Resources
– Financing Activities.
66
We will evaluate the level of capital spending and remain flexible throughout the year based on the following factors, among
others:
•
commodity prices, including price realizations on specific crude oil and natural gas production including the impact of
NGLs;
cash flows from operations;
operating and development costs and possible inflationary pressures;
permitting activity in the deepwater Gulf of Mexico;
drilling results;
•
•
•
•
• CONSOL Carried Cost Obligation (See Liquidity and Capital Resources - Off-Balance Sheet Arrangements)
•
•
•
•
•
•
property acquisitions and divestitures;
increase in exploration activities in new areas, including offshore Sierra Leone and the Falkland Islands;
availability of financing;
potential legislative or regulatory changes regarding the use of hydraulic fracturing;
potential changes in the fiscal regimes of the US and other countries in which we operate; and
impact of new laws and regulations, including implementation of the Dodd-Frank Wall Street Reform and Consumer
Protection Act, which has resulted in significant derivatives regulations and disclosure requirements, on our business
practices.
Exploration Program We continue to evaluate and build upon our significant exploration inventory in the onshore US,
deepwater Gulf of Mexico, offshore West Africa, offshore Eastern Mediterranean and other new international locations. During
2012, we expanded our global presence by entering into joint ventures in two new areas, offshore Falkland Islands and offshore
Sierra Leone, and by acquiring acreage in Northeast Nevada. Additionally, we drilled a successful exploratory well at Big
Bend in the deepwater Gulf of Mexico and drilled our first exploratory well at Scotia, offshore Falkland Islands.
In furtherance of our commitment to global offshore exploration and development, on September 27, 2012, we announced that
we have entered into a 36-month drilling services contract for a new-build drillship, the Atwood Advantage. See Items 1. and 2.
Business and Properties - International, above.
We continually evaluate and high-grade our exploration inventory to provide additional growth opportunities and potential new
core areas. In addition, each of our existing core areas has significant remaining exploration upside. We continue to leverage
existing activities to improve our exploratory programs in these core areas.
We devote significant capital to our exploration program. Approximately 15% of our $3.9 billion capital investment program in
2013 is dedicated to exploration and associated appraisal activities. However, we do not always encounter hydrocarbons
through our drilling activities. In addition, we may find hydrocarbons but subsequently reach a decision, through additional
analysis or appraisal drilling, that a project is not economically or operationally viable.
We are currently conducting, or planning to conduct, exploratory drilling activities in previously unexplored areas as well as
appraisal activities at several of our discoveries. In the event we conclude that one of our exploratory wells did not encounter
hydrocarbons or that a discovery is not economically or operationally viable, the associated capitalized exploratory well costs
would be charged to expense. As a result, in a future period, dry hole cost could be material. See Results of Operations - Oil
and Gas Exploration Expense, below. See also Item 1A. Risk Factors - Our entry into new exploration ventures in areas in
which we have no prior experience subjects us to additional risks.
Major Development Project Inventory Our current inventory of major development projects includes the horizontal
Niobrara, Marcellus Shale, Tamar, Alen, Diega and Carla, Gunflint, Big Bend, Leviathan, Cyprus and other West Africa gas
projects. These projects will require significant capital investments.
As noted above, we expect to spend substantial amounts on our major development projects in 2013. We plan to fund these projects
from cash flows from operations, cash on hand, and borrowings under our revolving credit facility and/or other financing.
The second of our major development projects brought online since 2011, Galapagos, located in the deepwater Gulf of Mexico,
began commercial crude oil production in June 2012 and two additional major development projects, Tamar, offshore Israel,
and Alen, offshore Equatorial Guinea, are on schedule to begin commercial production in 2013. The additional production from
these three major development projects, along with Aseng, offshore Equatorial Guinea, which began production in 2011, is
expected to begin generating significant cash flow which will be available to meet a substantial portion of future capital
requirements. See Liquidity and Capital Resources - Capital Structure/Financing Strategy.
67
As operator on the majority of our development projects, we pay gross 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 a
nonoperating partner may experience a delay in obtaining financing for its share of the joint venture costs. In addition, some of
our joint venture partners, including our partners in our Eastern Mediterranean projects, may not be as creditworthy as we are
and may experience liquidity problems. This could result in a delay in our receiving reimbursement of joint venture costs and
increases our counterparty credit risk. See Item 1A. Risk Factors – Failure to effectively execute our major development
projects could result in significant delays and/or cost over-runs, damage to our reputation, limitations on our growth and
negative effects on our operating results, liquidity and financial position, Failure of our partners to fund their share of
development costs or obtain project financing could result in delay or cancellation of future projects, thus limiting our growth
and future cash flows, and We are exposed to counterparty credit risk as a result of our receivables, hedging transactions, and
cash investments.
Potential for Future Asset Impairments We recorded asset impairment charges of $104 million during 2012. A further
decline in future NYMEX crude oil or natural gas prices could result in additional impairment charges. The cash flow model
that we use to assess proved properties for impairment includes numerous assumptions, such as management’s estimates of
future oil and gas production, market outlook on forward commodity prices, operating and development costs, and discount
rates. All inputs to the cash flow model must be evaluated at each date of estimate. However, a decrease in forward crude oil or
natural gas prices alone could result in impairment.
We are currently marketing certain non-core onshore US properties. If the properties are reclassified as assets held for sale, they
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. In addition, we would allocate a
portion of goodwill to any non-core onshore US property held for sale that constitutes a business, which could potentially
decrease any gain or increase any loss recorded on the sale.
Occasionally, well mechanical problems arise, which can reduce production and potentially result in reductions in proved
reserves estimates. For example, our South Raton development in the deepwater Gulf of Mexico is currently shut-in due to
mechanical issues. We are currently testing the well to determine appropriate remediation efforts. South Raton had a net book
value of approximately $116 million at December 31, 2012.
See Item 1A. Risk Factors – Crude oil, natural gas, and NGL prices are volatile and a reduction in these prices could
adversely affect our results of operations, our liquidity, and the price of our common stock. See Item 8. Financial Statements
and Supplementary Data – Note 4. Asset Impairments.
Climate Change Climate change has become the subject of an important public policy debate. While climate change remains a
complex issue, scientific research suggests that an increase in greenhouse gas emissions (GHGs) may pose a risk to society and
the environment. In 2011, the United Nations-sponsored Intergovernmental Panel on Climate Change, a scientific body which
provides an assessment of the risk of climate change, issued its Special Report on Managing the Risks of Extreme Events and
Disasters to Advance Climate Change Adaptation, in which it concluded that it is likely that climate change is fueling extreme
weather and predicted that there will be an escalation of impacts on people and economies.
In November 2012, the World Bank issued a report based on recent scientific literature and new analysis of likely impacts and
risks that would be associated with a 4oC warming within this century. Risks include rise in sea-levels, increases in tropical
cyclone intensity, increasing aridity and drought. The report predicted severe impacts on coastal cities, food and water systems,
ecosystems, and human health and called for international cooperation to prevent global warming. Also in 2012, a coalition of
institutional investors said that rapidly growing greenhouse gas and more extreme weather were increasing investment risks
globally and called on governments to increase action on climate change and boost investment in clean energy technology.
The oil and natural gas exploration and production industry is a source of certain GHGs, namely carbon dioxide and methane,
and future restrictions on the combustion of fossil fuels or the venting of natural gas could have a significant impact on our
future operations. We are actively monitoring the following climate change related issues:
Impact of Legislation and Regulation The commercial risk associated with the exploration and production of fossil fuels lies in
the uncertainty of government-imposed climate change legislation, including cap and trade schemes, carbon taxes, and regulations
that may affect us, our suppliers, and our customers. The cost of meeting these requirements may have an adverse impact on our
financial condition, results of operations and cash flows, and could reduce the demand for our products.
Climate change legislation and regulations have been adopted by many foreign countries and states in the US; however, legislation
and regulations have not been enacted in all of the foreign countries where we operate or at the federal level in the US. Due to the
current global economic environment and debt crisis, many countries are facing pressure to reduce spending or implement austerity
measures. This could result in the diverting of attention away from the environmental agenda as well as limited financial resources
available for spending on environmental policies. The status of development of many state and federal climate change regulatory
initiatives in areas where we operate makes it difficult to predict with certainty the future impact on us, including accurately
estimating the related compliance costs that we may incur.
68
The EPA issued regulations requiring monitoring and reporting of GHG emissions from petroleum and natural gas systems. This
action does not require control of GHGs. However, the EPA has indicated that it will use data collected through the reporting rules
to decide whether to promulgate future GHG limits. These and other US, and other international, regulations may affect our
operations by potentially increasing operating costs for maintaining our facilities, compliance costs for managing new GHG
regulatory programs and capital costs for installing new GHG emission controls.
Impact of International Accords The Kyoto Protocol to the United Nations Framework Convention on Climate Change (Protocol)
went into effect in February 2005 and required all industrialized nations that ratified the Protocol to reduce or limit GHG emissions
to a specified level by 2012. The US did not ratify the Protocol.
In December 2012, the annual conference of parties reconvened in Doha, Qatar, to continue pursuing the global accord, committing
countries to cut GHG emissions. The parties agreed to a second commitment period of the Kyoto Protocol which will last until
December 31, 2020.
While no specific new international climate change accord has been adopted that would affect our operating locations, the current
state of development of many initiatives makes it difficult to assess the timing or effect of any pending discussions of future accords
or predict with certainty the future costs that we may incur in order to comply with future international treaties or regulations.
Indirect Consequences of Regulation or Business Trends We believe there are both risks and opportunities arising from the global
response to potential climate change. See Items 1. and 2. Business and Properties – Regulations and the following risk factors
listed in Item 1A. Risk Factors –
• We are subject to increasing governmental regulations and environmental requirements that may cause us to incur
•
substantial incremental costs; and
The adoption of GHG emission or other environmental legislation could result in additional operating costs, create
delays in our obtaining air pollution permits for new or modified facilities, and reduce demand for the crude oil and
natural gas we produce.
In terms of opportunities, the regulation of GHGs and introduction of formal technology incentives, such as enhanced oil
recovery, carbon sequestration and low carbon fuel standards, could benefit us in a variety of ways.
First, approximately 54% of our 2012 total sales volumes from continuing operations were natural gas. GHG emissions regulation
could reduce the demand for the crude oil we produce. At the same time, the burning of natural gas produces lower levels of
emissions than other readily available fossil fuels such as crude oil and coal. Therefore, the use of natural gas may increase should
the use of other fossil fuels decrease due to GHG emissions regulation.
The 2011 incident at the Fukushima nuclear plant in Japan has re-opened debate about the future of nuclear power as an alternative
to fossil fuels, and public concern about nuclear safety has been heightened. In response, Germany, Japan, and other nations have
announced future shutdowns of nuclear plants and/or moratoria on future nuclear plant construction, resulting in increased demand
for alternate fuel sources, including natural gas, for power generation.
Furthermore, should renewable resources, such as wind or solar power become more prevalent, natural gas-fired electric plants
may provide an alternative backup to maintain consistent electricity supply.
Second, market-based incentives for the capture and storage of carbon dioxide in underground reservoirs, particularly in oil and
natural gas reservoirs, could benefit us through the potential to obtain GHG allowances or offsets from or government incentives
for the sequestration of carbon dioxide.
Finally, as the EPA’s new GHG standards for light duty vehicles became effective in 2011, natural gas may prove to be a more
attractive transportation fuel. This may increase the market demand for natural gas.
Physical Impacts of Climate Change on our Costs and Operations 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. Extreme weather conditions limit our production and increase our costs, and damage resulting from
extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change
may lead to increased storm or weather hazards affecting our operations, particularly our offshore operations and our onshore US
operations in the DJ Basin and Marcellus Shale. See Item 1A. Risk Factors – The insurance we carry is insufficient to cover all
of the risks we face, which could result in significant financial exposure.
Recently Issued Accounting Standards Update See Item 8. Financial Statements and Supplementary Data – Note 1.
Summary of Significant Accounting Policies.
69
RESULTS OF OPERATIONS
In the discussion below, prior year amounts have been reclassified to reflect the North Sea segment as discontinued operations.
See Discontinued Operations, below. Financial information presented is from continuing operations, unless otherwise noted.
Selected financial information is as follows:
(millions, except per share)
Total Revenues
Total Operating Expenses
Operating Income
Total Other (Income) Expense
Income from Continuing Operations Before Income Taxes
Income from Continuing Operations
Discontinued Operations, Net of Tax
Net Income
Earnings from Continuing Operations Per Share
Basic
Diluted
Year Ended December 31,
2012
2011
2010
$
$
4,223
2,811
1,412
56
1,356
965
62
1,027
5.43
5.37
$
3,404
2,870
534
32
502
412
41
453
2.34
2.31
2,713
1,944
769
(79)
848
631
94
725
3.61
3.56
Factors contributing to the increase in income from continuing operations before income taxes in 2012 as compared with 2011
included the following:
$819 million increase in total revenues due to higher sales volumes and higher average realized crude oil prices;
$129 million increase in gain on divestitures;
$33 million increase in gain on commodity derivative instruments; and
$653 million decrease in asset impairment charges;
Factors contributing to the decrease in income from continuing operations before income taxes in 2011 as compared with 2010
included the following:
•
•
•
•
offset by:
•
•
•
•
•
•
•
•
•
•
•
offset by:
•
$115 million increase in total production expense;
$132 million increase in exploration expense;
$492 million increase in DD&A expense; and
$45 million increase in general and administrative expense.
$43 million increase in total production expense;
$35 million increase in exploration expense;
$59 million increase in DD&A expense;
$66 million increase in general and administrative expense;
$88 million decrease in net gain on asset sales;
$613 million increase in asset impairment charges; and
$115 million decrease in gain on commodity derivative instruments;
See following discussion for explanation of year-to-year changes.
70
$691 million increase in total revenues due primarily to higher commodity prices and higher sales volumes.
Revenues
Oil, Gas and NGL Sales An analysis of the factors contributing to the changes in revenues from sales of crude oil, natural gas
and NGLs is as follows:
(millions)
2010 Sales Revenues
Changes due to
Increase in Sales Volumes
Increase in Sales Prices
Change in Amounts Reclassified from AOCL
2011 Sales Revenues
Changes due to
Increase (Decease) in Sales Volumes
Increase (Decrease) in Sales Prices
2012 Sales Revenues
Changes in revenue are discussed below.
Crude Oil &
Condensate
Natural
Gas
NGLs
Total
$
1,499
$
821
$
203
$
2,523
55
461
19
2,034
1,097
74
3,205
$
55
6
1
883
21
38
—
262
(34)
(229)
620
$
$
28
(78)
212
$
131
505
20
3,179
1,091
(233)
4,037
71
Oil, Gas and NGL Sales Average daily sales volumes and average realized sales prices were as follows:
Sales Volumes
Average Realized Sales Prices
Crude Oil &
Condensate
(MBbl/d)
Year Ended December 31, 2012
Natural
Gas
(MMcf/d)
NGLs
(MBbl/d)
Total
(MBoe/d)
Crude Oil &
Condensate
(Per Bbl)
Natural
Gas
(Per Mcf)
NGLs
(Per Bbl)
United States
Equatorial Guinea (1)
Israel
China
49
33
—
4
Total Consolidated
Operations
Equity Investees (2)
Total Continuing
Operations
Year Ended December 31, 2011
86
2
88
United States
Equatorial Guinea (1)
Israel
China
Total Consolidated
Operations
Equity Investees (2)
Total Continuing
Operations
38
14
—
4
56
2
58
Year Ended December 31, 2010
United States
Equatorial Guinea (1)
Israel
Ecuador (3)
China
Total Consolidated
Operations
Equity Investees (2)
Total Continuing
Operations
39
11
—
—
4
54
2
56
438
235
101
—
774
—
774
388
245
173
—
806
—
806
400
226
130
25
—
781
—
781
16
—
—
—
16
5
21
15
—
—
—
15
5
20
14
—
—
—
—
14
5
19
139
$
94.69
$
72
17
4
232
7
239
117
56
29
4
206
7
$
$
110.14
—
114.54
101.52
104.56
101.58
95.19
107.57
—
106.19
99.17
108.76
$
$
2.61
0.27
4.85
—
2.19
—
2.19
3.90
0.27
4.86
—
3.00
—
$
35.36
—
—
—
35.36
69.14
44.15
48.35
—
—
—
48.35
72.71
$
$
213
$
99.46
$
3.00
$
54.84
119
$
75.03
$
49
22
4
4
198
7
78.44
—
—
75.15
75.76
77.98
4.17
0.27
4.03
—
—
2.98
—
$
41.21
—
—
—
—
41.21
53.68
205
$
75.83
$
2.98
$
44.90
(1) Natural gas from the Alba field in Equatorial Guinea is under contract for $0.25 per MMBtu to a methanol plant, an LPG plant and an
LNG plant. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method of accounting.
(2) Volumes represent sales of condensate and LPG from the Alba plant in Equatorial Guinea. See Income from Equity Method Investees
below.
(3)
Includes sales volumes through November 24, 2010. Our Block 3 PSC was terminated by the Ecuadorian government on November 25,
2010. Intercompany natural gas sales were eliminated for accounting purposes. Electricity sales are included in other revenues. See Item
8. Financial Statements and Supplementary Data - Note 3. Acquisitions and Divestitures.
72
If the realized gains and losses on commodity derivative instruments, which are included in (gain) loss on commodity
derivative instruments in our consolidated statements of operations, had been included in oil and gas revenues, the effect on
average realized prices would have been as follows:
Commodity Price Increase (Decrease)
Year Ended December 31,
2011
2012
2010
Crude Oil &
Condensate
(Per Bbl)
Natural
Gas
(Per Mcf)
Crude Oil &
Condensate
(Per Bbl)
Natural
Gas
(Per Mcf)
Crude Oil &
Condensate
(Per Bbl)
Natural
Gas
(Per Mcf)
$
(0.48) $
(6.17)
(2.62)
(2.57)
$
0.30
—
0.17
0.17
(3.22) $
—
(2.16)
(2.10)
$
0.77
—
0.37
0.37
(0.65) $
(3.41)
(1.18)
(1.15)
0.76
—
0.40
0.40
United States
Equatorial Guinea
Total Consolidated Operations
Total Continuing Operations
Crude Oil and Condensate Sales Revenues from crude oil and condensate sales increased by $1.2 billion, or 58% in 2012 as
compared with 2011 due to the following:
•
•
•
•
higher sales volumes in the DJ Basin attributable to the acceleration of our horizontal drilling programs in the
Wattenberg area;
commencement of production at Galapagos and South Raton in the deepwater Gulf of Mexico which increased
production by approximately seven MBoe/d, net, during 2012;
higher sales volumes in Equatorial Guinea due to the commencement of oil production at Aseng during the fourth
quarter of 2011, which impacted our sales volumes by approximately 21 MBbl/d, net, in 2012 as compared with 2011;
and
a 2% increase in total consolidated average realized prices primarily due to higher Brent pricing resulting from the
global economic recovery
partially offset by
•
•
•
reduction in sales volumes due to the sales of non-core, onshore US properties during the third quarter of 2012;
a volume reduction in the Gulf of Mexico of nearly seven MBoe/d as a result of shut-ins due to Hurricane Isaac; and
natural field decline in non-core onshore US and deepwater Gulf of Mexico areas.
Revenues from crude oil and condensate sales increased by $535 million, or 36%, in 2011 as compared with 2010 due to the
following:
•
•
•
a 31% increase in total consolidated average realized prices due to increased demand resulting from the global economic
recovery;
higher sales volumes in the DJ Basin, including a 21% increase in Wattenberg sales volumes, attributable to the
continued acceleration of our horizontal Niobrara development project; and
higher sales volumes in Equatorial Guinea due to a higher number of liftings from our Alba field and due to the
commencement of oil production at Aseng which impacted our sales volumes by approximately 9 MBbl/d in the fourth
quarter;
partially offset by
•
•
a decrease in onshore US volumes due to the divestment of non-core oil assets; and
a decrease in deepwater Gulf of Mexico volumes due to natural field decline and third party downstream facility
constraints.
Revenues from crude oil and condensate sales included deferred losses of $19 million in 2010 reclassified from AOCL related
to commodity derivative instruments previously accounted for as cash flow hedges. As of December 31, 2010, there were no
further amounts related to commodity derivative instruments remaining to be reclassified from AOCL to crude oil revenues.
See Item 8. Financial Statements and Supplementary Data – Note 10. Derivative Instruments and Hedging Activities.
73
Natural Gas Sales Revenues from natural gas sales decreased by $263 million, or 30%, in 2012 as compared with 2011 due to
the following:
•
•
•
decreases in US average realized prices primarily due to oversupply and above average levels of natural gas in storage;
lower sales volumes due to the sales of non-core onshore US properties during the third quarter of 2012;
lower sales volumes in the Wattenberg and Rocky Mountain areas of our US operations due to third-party processing
facility constraints;
lower sales volumes from the Alba field, offshore Equatorial Guinea, due to scheduled maintenance activities at the non-
operated Alba facilities; and
lower sales volumes in Israel due to a reduction in the rate of production from the Mari-B field in order to manage the
reservoir;
partially offset by
•
•
•
•
higher sales volumes attributable to the acceleration of our horizontal drilling programs in the Wattenberg area; and
new sales volumes from Marcellus Shale producing properties which we acquired September 30, 2011 and current
Marcellus Shale development activities, which added 90 MMcf/d, net to our sales volumes for 2012.
Revenues from natural gas sales increased by $62 million, or 8%, in 2011 as compared with 2010 due to the following:
•
•
•
•
•
higher natural gas prices in Israel which benefit from strong global liquids markets;
an increase in Israel sales volumes due to an increase in demand for our natural gas driven by higher electricity
production and lower levels of competitor natural gas imports from Egypt;
higher sales volumes in the DJ Basin, including a 10% increase in Wattenberg sales volumes, attributable to the
continued acceleration of our vertical and horizontal Niobrara drilling programs in the Wattenberg area;
sales volumes from Marcellus Shale producing properties which we acquired September 30, 2011 and which added 19
MMcf/d to our 2011 sales volumes; and
higher sales volumes in Equatorial Guinea as compared with 2010, during which time the Alba field experienced a
planned shut-down for facilities maintenance and repair;
partially offset by
•
•
•
a decrease in US realized natural gas prices which declined during 2011 primarily due to oversupply;
a decrease in onshore US sales volumes due to the sale of certain non-core Oklahoma and Illinois Basin assets in 2010;
and
natural field decline in the deepwater Gulf of Mexico, Gulf Coast and Mid-Continent areas.
Revenues from natural gas included a deferred loss of $1 million in 2010 reclassified from AOCL related to commodity
derivative instruments previously accounted for as cash flow hedges. As of December 31, 2010, there were no further amounts
related to commodity derivative instruments remaining to be reclassified from AOCL to natural gas revenues. See Item 8.
Financial Statements and Supplementary Data – Note 10. Derivative Instruments and Hedging Activities.
NGL Sales Most of our US NGL production is from the Wattenberg area. NGL sales revenues decreased $50 million, or 19%,
during 2012 as compared with 2011 as a result of lower realized prices offset by an increase in sales volumes. Our average
realized prices declined 27% during 2012 compared to 2011 primarily due to higher supplies of NGLs resulting from increased
wet gas drilling activities.
NGL sales revenues increased $59 million, or 29%, during 2011 as compared with 2010 due to higher realized prices and a
slight increase in sales volumes due to ongoing development in the DJ Basin.
Income from Equity Method Investees We have a 45% interest in AMPCO, which owns and operates a methanol plant and related
facilities, and a 28% interest in Alba Plant, which owns and operates an LPG processing plant. Both plants and related facilities
are located onshore Bioko Island in Equatorial Guinea. We also have a 50% interest in CONE Gathering LLC (CONE), which
owns and operates natural gas gathering facilities servicing our joint venture properties in the Marcellus Shale. We account for
investments in entities that we do not control but over which we exert significant influence using the equity method of accounting.
74
Our share of operations of equity method investees was as follows:
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)
Year Ended December 31,
2012
2011
2010
$
$
$
64
122
70
130
156
2
5
$
68
125
86
139
155
2
5
29
89
44
95
129
2
5
$
1.07
104.56
69.14
$
1.05
108.76
72.71
0.84
77.98
53.68
AMPCO and Affiliates Net income from AMPCO and affiliates decreased in 2012 as compared with 2011 primarily due to
increased other non-operating expense.
Net income from AMPCO and affiliates increased in 2011 as compared with 2010 due to increases in average realized
methanol prices due to global economic recovery, and increases in methanol sales volumes as compared with 2010 when the
plant experienced down time related to a major turnaround.
Alba Plant Net income from Alba Plant decreased slightly in 2012 as compared with 2011 due to lower realized price.
Net income from Alba Plant increased in 2011 as compared with 2010 due to increases in average realized condensate and LPG
prices due to global economic recovery.
CONE Gathering LLC Under the terms of the gathering and marketing agreement that we entered into with CONE, we will
pay CONE a minimum annual revenue commitment (MARC). The fee will be adjusted annually based on projected gathering
volumes, operating expenses, capital expenditures, and other factors. Our share of CONE earnings were de minimis for the year
ended December 31, 2012 and 2011. During 2012, we contributed $41 million to CONE. See Item 8. Financial Statements and
Supplementary Data – Note 3. Acquisitions and Divestitures.
Other Revenues Other revenues were as follows:
(millions)
Other Revenues
Year Ended December 31,
2012
2011
2010
$
— $
32
$
72
Other revenues include electricity sales from the Machala power plant, located in Machala, Ecuador, (through May 2011) and
other revenue items. See Item 8. Financial Statements and Supplementary Data – Note 2. Additional Financial Statement
Information.
75
Operating Costs and Expenses
Operating costs and expenses were as follows:
(millions)
Production Expense
Exploration Expense
Depreciation, Depletion and Amortization
General and Administrative
Gain on Divestitures
Asset Impairments
Other Operating (Income) Expense, Net
Total
Inc(Dec)
from
Prior Year
Inc(Dec)
from
Prior Year
2011
2012
2010
$
$
673
409
1,370
384
(154)
104
25
2,811
21 % $
48 %
56 %
13 %
516 %
(86)%
(71)%
(2)% $
558
277
878
339
(25)
757
86
2,870
8 %
14 %
7 %
24 %
(78)%
426 %
34 %
48 %
515
242
819
273
(113)
144
64
1,944
Changes in operating costs and expenses are discussed below.
Production Expense Components of production expense were as follows:
(millions, except unit rate)
Year Ended December 31, 2012
Lease Operating Expense (3)
Production and Ad Valorem Taxes
Transportation and Gathering Expense
Total Production Expense
Total Production Expense per BOE
Year Ended December 31, 2011
Lease Operating Expense (3)
Production and Ad Valorem Taxes
Transportation and Gathering Expense
Total Production Expense
Total Production Expense per BOE
Year Ended December 31, 2010
Lease Operating Expense (3)
Production and Ad Valorem Taxes
Transportation and Gathering Expense
Total Production Expense
Total Production Expense per BOE
Total per
BOE (1)
Total
United
States
Equatorial
Guinea
Israel
Other Int'l,
Corporate (2)
$
$
$
$
$
$
5.09
1.79
1.06
7.94
4.47
1.88
0.85
7.20
4.39
1.67
0.83
6.89
$
$
$
$
$
$
$
$
$
431
151
91
673
7.94
346
146
66
558
7.20
329
125
61
515
6.89
$
$
$
$
$
$
$
$
$
287
113
87
487
9.60
254
102
63
419
9.85
258
103
59
420
9.69
$
$
$
$
$
$
$
$
$
89
—
—
89
3.39
53
—
—
53
2.64
43
—
—
43
2.38
$
$
$
$
$
$
$
$
$
20
—
—
20
3.23
12
—
—
12
1.16
9
—
—
9
$
$
$
$
$
$
35
38
4
77
N/M
27
44
3
74
N/M
19
22
2
43
1.15
N/M
N/M Amount is not meaningful. See (2) below.
(1) Consolidated unit rates exclude sales volumes and costs attributable to equity method investees
(2) Other international includes China and unallocated expenses incurred at the corporate level.
(3) Lease operating expense includes oil and gas operating costs (labor, fuel, repairs, replacements, saltwater disposal and other related lifting
costs) and workover and repair expense.
76
•
•
•
offset by
•
Lease Operating Expense Lease operating expense was $431 million in 2012 as compared with $346 million 2011, a 25%
increase. Changes included the following:
•
•
•
•
•
higher sales volumes from the Wattenberg area due to ongoing development activities accounted for an increase of $24
million in US lease operating expense;
new production at Galapagos and higher production handling costs at Swordfish, deepwater Gulf of Mexico, accounted for
an increase of $22 million;
a full year of production from Marcellus Shale properties acquired in 2011, and additional development activity accounted
for an increase of $17 million;
lease operating expense associated with the Aseng field, offshore Equatorial Guinea, which began producing in
November 2011, accounted for an increase of $36 million; and
the start-up of the Noa and Pinnacles wells, offshore Israel, in second quarter of 2012 accounted for an increase of $8
million;
partially offset by
•
lower volumes in the US due to the sale of non-core onshore US properties during the third quarter of 2012.
Lease operating expense increased in 2011 as compared to 2010 due to the following:
higher US sales volumes from the DJ Basin due to ongoing development activities;
higher sales volumes in Equatorial Guinea and Israel; and
higher operating costs associated with the Aseng field which began producing in November 2011;
the sale of certain Oklahoma and Illinois Basin assets in 2010, which had higher lease operating costs.
Production and Ad Valorem Tax Expense In the US, taxes increased in 2012 as compared with 2011 due to the enactment of
the annual Marcellus Shale well impact fee by the Pennsylvania legislature in first quarter 2012. This enactment increased
taxes approximately $8 million, of which approximately $4 million related to wells spud prior to 2012. Additionally, higher
volumes for the Wattenberg area resulted in an increase of $15 million. This increase was offset by non-core onshore US
property sales during 2012.
Production and ad valorem tax expense decreased in 2011 as compared with 2010 due to the sale of certain non-core Oklahoma
and Illinois Basin assets in 2010 and natural field decline in the Mid-Continent area. This decrease was offset by higher
production and ad valorem taxes in the DJ Basin due to increased production volumes and higher sales prices. Production and
ad valorem tax expense for 2011 increased in China as compared with 2010 due to higher sales prices.
Transportation Expense Transportation expense increased in 2012 as compared with 2011. Higher US crude oil sales volumes
from the DJ Basin as a result of ongoing development activities resulted in an increase of $21 million. A full year of production
from our Marcellus Shale producing properties, acquired on September 30, 2011, resulted in an increase of $8 million. These
increases were offset by reductions in transportation expense due to non-core onshore US property sales during the third quarter
of 2012.
Transportation expense increased in 2011 as compared with 2010 due to higher sales volumes in the DJ Basin and new
production from our Marcellus Shale producing properties acquired on September 30, 2011, offset by lower transportation
expense in the deepwater Gulf of Mexico due to declining production.
Unit Rate Per BOE The unit rate of total production expense per BOE increased for 2012 as compared with 2011 primarily
due to a change in the mix of production, including new production at Galapagos and South Raton, and the start-up of the Noa
and Pinnacles wells, each of which has a higher production rate than our other projects, and the enactment of the Marcellus
Shale well impact fee.
The unit rate of total production expense per BOE increased for 2011 as compared with 2010 primarily due to higher
production tax rates on certain onshore US and China production, transportation charges related to Marcellus Shale producing
properties and the startup of the Aseng field.
77
Exploration Expense Components of exploration expense were as follows:
Total
United
States
West
Africa (1)
Eastern
Mediterranean (2)
Other Int'l,
Corporate (3)
(millions)
Year Ended December 31, 2012
Dry Hole Cost
Seismic
Exploration Expense
Other
Total Exploration Expense
Year Ended December 31, 2011
Dry Hole Cost
Seismic
Exploration Expense
Other
Total Exploration Expense
Year Ended December 31, 2010
Dry Hole Cost
Seismic
Exploration Expense
Other
$
155
$
121
$
$
$
$
$
81
148
25
409
105
63
94
15
277
58
102
66
16
$
$
$
$
59
22
23
225
46
33
22
15
116
54
51
10
15
$
$
$
$
Total Exploration Expense
$
242
$
130
$
34
4
49
1
88
59
1
7
—
67
3
5
6
—
14
$
$
$
$
$
$
— $
—
5
—
5
$
— $
4
2
—
6
$
— $
11
2
—
13
$
—
18
72
1
91
—
25
63
—
88
1
35
48
1
85
(1) West Africa includes Equatorial Guinea, Cameroon, Sierra Leone, and Senegal/Guinea-Bissau.
(2) Eastern Mediterranean includes Israel and Cyprus.
(3) Other International includes various international new ventures such as offshore Nicaragua and offshore Falkland Islands.
Oil and gas exploration expense increased in 2012 as compared with 2011 due to the following:
•
• US dry hole expense associated with the Deep Blue exploratory well (deepwater Gulf of Mexico) totaled $117 million.
Although Deep Blue was successful in locating hydrocarbons, we decided not to develop the prospect due to near-term
lease expiration as well as other considerations;
dry hole expense in West Africa related to the Trema exploratory well, which found noncommercial quantities of
hydrocarbons, totaled $32 million;
exploration expense in West Africa includes $40 million for the non-operated AGC Profond block offshore Senegal/
Guinea-Bissau, which was written off during the third quarter of 2012 when we decided not to proceed with additional
appraisal activities. We relinquished our acreage;
seismic expenditures related to the deepwater Gulf of Mexico lease sale and international new ventures; and
exploration expense also includes staff expense associated with new ventures and corporate expenditures.
•
•
•
Oil and gas exploration expense increased in 2011 as compared with 2010 due to the following:
•
• US dry hole expense was associated with the Rocky Mountain area and the Redrock exploration well in the deepwater
Gulf of Mexico, which we decided not to pursue for development due to the significant decline in natural gas prices;
dry hole expense in West Africa related to the Kora-1 exploration well offshore Senegal/Guinea-Bissau and the Bwabe
exploration well offshore Cameroon, which found noncommercial quantities of hydrocarbons;
seismic expenditures related to acquisition of information for Wattenberg, Rocky Mountain and deepwater Gulf of
Mexico areas in the US, offshore Nicaragua, offshore France, and offshore Cyprus; and
increases in staff expense were due to new ventures mainly offshore Nicaragua and offshore France.
•
•
Exploration expense included stock-based compensation expense of $12 million in 2012, $11 million in 2011, and $10 million
in 2010.
78
Depreciation, Depletion and Amortization DD&A expense was as follows:
Year Ended December 31,
2011
2010
2012
(millions, except unit rate)
United States
Equatorial Guinea
Israel
Other International, Corporate, and Other
Total DD&A Expense (1)
Unit Rate per BOE (2)
$
$
$
929
255
111
75
1,370
16.16
$
$
$
732
69
25
52
878
11.32
$
$
$
719
39
22
39
819
10.94
(1) DD&A expense includes accretion of discount on asset retirement obligations of $22 million in 2012, $13 million in 2011, and $13
million in 2010.
(2) Consolidated unit rates exclude sales volumes and costs attributable to equity method investees.
Total DD&A expense increased for 2012 as compared with 2011 due to the following:
•
•
•
•
•
higher sales volumes in the DJ Basin onshore US accounted for $189 million of the increase and the addition of DD&A
expense related to the Marcellus Shale accounted for $46 million of the increase;
the start up of Noa and Pinnacles (offshore Israel), which have higher DD&A rates, accounted for $86 million of the
increase;
the start up of Galapagos and South Raton in the deepwater Gulf of Mexico, which have higher DD&A rates, accounted
for $92 million of the increase;
a full year of production from the Aseng field, offshore Equatorial Guinea, which includes the Aseng FPSO in its
depreciation base, accounted for $183 million of the increase; and
higher costs associated with development activities in China;
partially offset by
•
the impact of sales of non-core, onshore US properties during 2012.
Changes in the unit rate per BOE for 2012 as compared with 2011 were due to changes in the mix of production, primarily due
to volumes from the start-up of the Galapagos, Noa, Pinnacles and South Raton projects and a full year of production from
Aseng, which have comparatively higher DD&A rates, and increased horizontal drilling activity.
Total DD&A expense increased for 2011 as compared with 2010 due to the following:
•
•
•
•
higher sales volumes in the DJ Basin of our onshore US operations resulting from ongoing capital spending;
higher sales volumes in Equatorial Guinea and the startup of the Aseng field which includes the Aseng FPSO in its
depreciation base;
higher costs associated with development activities in China; and
the impact of negative reserves revisions at December 31, 2011, due to revised performance expectations in the North
Sea and China;
partially offset by
•
lower sales volumes in the deepwater Gulf of Mexico, Gulf Coast, and Mid-Continent areas of our US operations
resulting from natural field decline.
79
General and Administrative Expense General and administrative expense (G&A) was as follows:
Year Ended December 31,
2011
2010
2012
G&A Expense (millions)
Unit Rate per BOE (1)
$
$
384
4.53
$
339
4.37
273
3.65
(1) Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
G&A expense for 2012 increased as compared with 2011 primarily due to additional personnel and office space supporting
growth in the Wattenberg and Marcellus Shale core areas and augmentation of environmental, health and safety, geoscience,
and information technology departments in support of our major development projects and increased exploration activities, and
increased performance incentive compensation.
G&A expense increased for 2011 as compared with 2010 primarily due to additional expenses relating to personnel, office costs
and information technology costs in support of our major development and exploration projects and increased performance
incentive compensation.
G&A expense is impacted by the number of stock-based awards, the market price of our common stock and price volatility, all
of which result in a higher fair value of stock-based awards as calculated using the Black-Scholes-Merton option pricing model.
G&A included stock-based compensation expense of $48 million in 2012, $42 million in 2011 and $39 million in 2010. See
Item 8. Financial Statements and Supplementary Data – Note 14. Stock-Based and Other Compensation Plans.
Gain on Divestitures Gain on divestitures was as follows:
(millions)
Gain on Divestitures
Year Ended December 31,
2012
2011
2010
$
(154) $
(25) $
(113)
Gain on divestitures for 2012 is related to the sale of certain non-core onshore US assets. See Item 8. Financial Statements and
Supplementary Data – Note 3. Acquisitions and Divestitures.
Gain on divestitures for 2011 includes a $25 million gain on the transfer of assets and the associated PSC and electricity
concession to the Ecuadorian government. Gain on divestitures for 2010 includes a $110 million gain on the sale of certain
non-core assets in the Mid-Continent and Illinois Basin areas. See Item 8. Financial Statements and Supplementary Data –
Note 3. Acquisitions and Divestitures.
Asset Impairments Asset impairment expense was as follows:
(millions)
Asset Impairments
Year Ended December 31,
2012
2011
2010
$
104
$
757
$
144
For information regarding asset impairment charges, see Critical Accounting Policies and Estimates – Impairment of Proved
Oil and Gas Properties and Other Investments and Impairment of Unproved Oil and Gas Properties, below, and Item 8.
Financial Statements and Supplementary Data – Note 4. Asset Impairments.
Other Operating Expense, Net Other operating expense, net was as follows:
(millions)
Deepwater Gulf of Mexico Moratorium Expense
Electricity Generation Expense
Other (Income) Expense, Net
Total
Year Ended December 31,
2012
2011
2010
$
$
— $
—
25
25
$
18
26
42
86
$
$
27
39
(2)
64
See Item 8. Financial Statements and Supplementary Data – Note 2. Additional Financial Statement Information.
80
Other (Income) Expense Other (income) expense was as follows:
(millions)
Gain on Commodity Derivative Instruments
Interest, Net of Amount Capitalized
Other Non-Operating (Income) Expense, Net
Total
Year Ended December 31,
2012
2011
2010
$
$
(75) $
125
6
56
$
(42) $
65
9
32
$
(157)
72
6
(79)
See Item 8. Financial Statements and Supplementary Data – Note 2. Additional Financial Statement Information.
Gain on Commodity Derivative Instruments We recognize all gains and losses on commodity derivative instruments in
earnings in the period in which they occur. See Critical Accounting Policies and Estimates – Derivative Instruments and
Hedging Activities, below, and Item 8. Financial Statements and Supplementary Data – Note 10. Derivative Instruments and
Hedging Activities and Note 15. Fair Value Measurements and Disclosures.
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,
2012
2011
2010
$
$
$
276
(151)
125
1.48
$
$
$
197
(132)
65
0.84
$
$
$
139
(67)
72
0.96
(1) Consolidated unit rates exclude sales volumes and costs attributable to equity method investees.
Interest expense prior to the reduction of capitalized interest increased $79 million from 2011 to 2012 due to our December
2011 debt issuance, an additional month of interest for our February 2011 debt issuance and interest related to our Aseng FPSO
lease obligation.
Interest expense prior to the reduction of capitalized interest increased $58 million in 2011 as compared with 2010 resulting
from a higher outstanding debt balance during the period and the interest associated with our 2011 public debt issuances. The
higher rate on the senior unsecured notes replaced the substantially lower rate applicable to our revolving credit facility which
was repaid with proceeds from our debt offering.
The increase of $19 million in the amount of interest capitalized in 2012 compared to 2011 is due to higher work in progress
amounts related to major long-term projects in the deepwater Gulf of Mexico, offshore West Africa, and Eastern Mediterranean.
The increase of $65 million in the amount of interest capitalized in 2011 compared to 2010 is due to higher work in progress
amounts related to major long lead-time projects in the deepwater Gulf of Mexico, offshore West Africa, and Eastern
Mediterranean and a higher weighted average interest rate due to our fixed rate senior unsecured note issuances in 2011, which
impacted the average rate we pay on long-term debt.
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 deepwater Gulf of Mexico,
offshore West Africa and offshore Eastern Mediterranean. See Item 8. Financial Statements and Supplementary Data – Note 7.
Capitalized Exploratory Well Costs.
Other Non-operating (Income) Expense, Net Other non-operating (income) expense, net includes deferred compensation
(income) expense, interest income and other (income) expense, net. See Item 8. Financial Statements and Supplementary Data
– Note 2. Additional Financial Statement Information.
81
Deferred Compensation (Income) Expense We have assets and liabilities related to a deferred compensation plan. The assets
of the deferred compensation plan are held in a rabbi trust and include shares of our common stock and mutual fund
investments. At December 31, 2012, approximately 48% of the market value of the assets in the rabbi trust related to our
common stock. Increases in the market value of our common stock held in the trust result in the recognition of deferred
compensation expense. Decreases in the market value of our common stock held in the trust result in the recognition of
deferred compensation income. We recognized deferred compensation expense of $6 million in 2012, $8 million in 2011, and
$15 million in 2010. See Item 8. Financial Statements and Supplementary Data – Note 14. Stock-Based and Other
Compensation Plans.
Income Tax Provision The income tax provision was as follows:
(millions)
Income Tax Provision
Effective Rate
Year Ended December 31,
2012
2011
2010
$
$
391
28.8%
$
90
17.9%
217
25.6%
See Item 8. Financial Statements and Supplementary Data – Note 13. Income Taxes.
Discontinued Operations
Summarized results of discontinued operations, comprising our North Sea geographical segment, were as follows:
Year Ended December 31,
2012
2011
2010
millions
Oil and Gas Sales
Less:
Production Expense
DD&A Expense
Other Expense, Net (1)
Income Before Income Taxes
Income Tax Expense
Operating Income, Net of Tax
Gain on Sale, Net of Tax
Key Statistics:
Daily Production
Crude Oil & Condensate (MBbl/d)
Natural Gas (MMcf/d)
Average Realized Price
Crude Oil & Condensate (Per Bbl)
Natural Gas (Per Mcf)
Discontinued Operations, Net of Tax
$
$
208
$
357
$
44
33
30
101
55
46
16
62
5
4
$
58
87
(3)
215
174
41
—
41
8
5
$
$
112.94
8.62
112.97
8.11
309
55
64
7
183
89
94
—
94
10
6
80.24
5.35
(1)
Includes exploration expense of $27 million in 2012 related to the Selkirk field. During 2012, the nearby Bligh well, a potential co-
development candidate for Selkirk, was drilled. Bligh encountered hydrocarbons but disappointingly tight non-commercial reservoirs.
Therefore, we determined that Selkirk was uneconomic for joint development.
Our long-term debt is recorded at the consolidated level and is not reflected by each component. Thus, we have not allocated
interest expense to discontinued operations.
See Item 8. Financial Statements and Supplementary Data – Note 3. Acquisitions and Divestitures.
82
PROVED RESERVES
We have historically added reserves through our exploration program, development activities, and acquisition of producing
properties. (See Items 1. and 2. Business and Properties). Changes in proved reserves were as follows:
(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
Year Ended December 31,
2012
2011
2010
1,209
(97)
218
—
(57)
(89)
1,184
1,092
(50)
180
68
—
(81)
1,209
820
5
360
47
(61)
(79)
1,092
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, or development costs. Revisions
included the following:
•
•
•
changes for the year ended December 31, 2012 included a negative revision of 94 MMBoe due to our decision to
terminate the legacy vertical drilling program in Wattenberg and focus on the horizontal development of the Niobrara;
net positive revisions of 23 MMBoe, primarily related to better than expected well performance in the Marcellus Shale,
the deepwater Gulf of Mexico, and the Aseng field; and negative revisions of 26 MMBoe due to changes in commodity
prices;
changes for the year ended December 31, 2011 include a negative revision of 28 MMBoe, due primarily to
reclassifications of proved undeveloped reserves in Wattenberg that are no longer expected to be developed within five
years due to additional shifting of activity from vertical to horizontal development, a negative revision of 10 MMBoe
due to reduced activity assumptions for dry gas properties onshore US, as well as other lesser revisions in various other
areas related to well performance and changes in commodity prices; and
changes for the year ended December 31, 2010 included a positive revision of 43 MMBoe due to higher year-end
commodity prices, a negative revision of 30 MMBoe due to reclassifications of proved undeveloped reserves to
probable reserves as a result of the SEC’s five year development rule, a negative revision of 7 MMBoe due to a change
in the likelihood that the Noa field, offshore Israel, would be pursued for development, and a negative revision of 2
MMBoe due to well performance.
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 included the following:
•
•
•
changes for the year ended December 31, 2012 included an increase of 149 MMBoe in the DJ Basin as a result of our
decision to focus capital and resources on horizontal development of the Niobrara, 56 MMBoe related to ongoing
development of the Marcellus Shale, 7 MMBoe related to the ongoing appraisal of Tamar, and 6 MMBoe for other
projects;
changes for the year ended December 31, 2011 included increases of 97 MMBoe in the onshore US, primarily associated
with horizontal drilling in the DJ Basin and development activities in the Marcellus Shale, 80 MMBoe at Tamar due to
appraisal activities, and 3 MMBoe for other projects; and
changes for the year ended December 31, 2010 included an increase of 48 MMBoe, which were primarily driven by the
execution of low-risk development projects onshore in Wattenberg and the Rocky Mountain area, an increase of 286
MMBoe related to the initial recording of reserves for the Tamar field offshore Israel, and an increase of approximately
27 MMBoe related to the initial recording of reserves for the Alen field, offshore Equatorial Guinea.
83
We expect that a significant portion of future reserves additions will come from our major development projects at the DJ
Basin, Marcellus Shale, Gunflint, Tamar and Leviathan and from new discoveries resulting from our active exploration
programs in both core areas and global new ventures programs. We may also purchase proved properties in strategic
acquisitions. See Operating Outlook – Major Development Project Inventory, above, and Liquidity and Capital Resources -
Acquisition, Capital and Other Exploration Expenditures, below.
Purchase of Minerals in Place We occasionally enhance our asset portfolio with strategic acquisitions of producing
properties. Purchases included the following:
•
•
the Marcellus Shale asset acquisition in 2011; and
the DJ Basin asset acquisition in 2010.
Sale of Minerals in Place We maintain an ongoing portfolio management program. Sales included the following:
•
•
the sale of non-core, onshore US assets in the Kansas, western Oklahoma, west Texas and Wyoming areas and the North
Sea in 2012; and
the sale of non-core assets in the Mid-Continent and Illinois Basin areas in 2010.
Sales of Minerals in Place also included a reduction in natural gas reserves due to the Ecuadorian government’s termination of
our Block 3 PSC in November 2010. See Items 1. and 2. Business and Properties and Item 8. Financial Statements and
Supplementary Data – Note 3. Acquisitions and Divestitures.
Production See Results of Operations – Revenues – Oil, Gas and NGL Sales, above.
See also Critical Accounting Policies and Estimates – Reserves, below, and Item 8. Financial Statements and Supplementary
Data – Supplemental Oil and Gas Information (Unaudited).
LIQUIDITY AND CAPITAL RESOURCES
Capital Structure/Financing Strategy
In seeking to effectively fund and monetize our major development projects, we employ a capital structure and financing
strategy designed to provide sufficient liquidity throughout the commodity price cycle. Specifically, we strive to retain the
ability to fund long cycle, multi-year, capital intensive development projects throughout a range of scenarios, while also
maintaining the capability to execute a robust exploration program and capitalize on financially attractive periodic mergers and
acquisitions activity. We endeavor to maintain an investment grade debt rating in service of these objectives, while delivering
competitive returns and a growing dividend. We also utilize a commodity price hedging program to reduce the impacts of
commodity price volatility and enhance the predictability of cash flows along with a risk and insurance program to protect
against disruption to our cash flows and the funding of our business.
Our current line-up of major development projects, as well as our planned exploration and appraisal drilling activities, will
result in capital expenditures exceeding cash flows from operating activities over the near term. The amount by which capital
investment will exceed operating cash flows depends on our success in sanctioning future development projects, the results of
our exploration activities, and new business opportunities. To support our investment program, we expect that higher
production resulting from our accelerated horizontal Niobrara development program combined with new production from
Tamar and Alen will result in an increase in cash flows which will be available to meet a substantial portion of future capital
requirements. In addition, our current liquidity level and strong balance sheet provide flexibility. We believe that we are well-
positioned to fund our long-term growth plans. See Available Liquidity, below.
We are currently evaluating potential development scenarios for our significant natural gas discoveries offshore Eastern
Mediterranean, including Leviathan and Cyprus Block 12. The magnitude of these discoveries presents financial and technical
challenges for us due to the large-scale development requirements. Potential development scenarios may include the
construction of LNG terminals, floating LNG, subsea pipeline or other options. Each of these development options would
require a multi-billion dollar investment and require a number of years to complete. We have announced a potential strategic
partner for Leviathan, Woodside, who could provide midstream expertise as well as LNG project execution and marketplace
expertise. We are in the process of negotiating a definitive agreement. See Items 1. and 2. Business and Properties - Acquisition
and Divestiture Activities.
We strive to maintain a minimum liquidity level to address volatility and risk. Traditional sources of our liquidity are cash on
hand, cash flows from operations, available borrowing capacity under our credit facility, and proceeds from sales of non-core
properties, such as certain onshore US and North Sea properties in 2012. We may also access debt and/or capital markets for
additional financing, such as an issuance of long-term debt or project finance, for our large development projects. We exercised
our option to increase our Credit Facility's overall commitment amount by an additional $1.0 billion, on September 28, 2012.
See Credit Facility below. See also Item 1A. Risk Factors - Unavailability of capital resources at reasonable cost could have a
negative impact on our liquidity and limit our growth.
84
Marcellus Shale Joint Venture Our joint venture arrangement with a subsidiary of CONSOL Energy, Inc. is structured in a
manner to address partner alignment and financial affordability. We spread the $1.3 billion acquisition cost over a three-year
period, beginning at closing. The $2.1 billion CONSOL Carried Cost Obligation is expected to extend over a multi-year period
and is capped at $400 million maximum in each calendar year. The obligation is suspended if average Henry Hub natural gas
prices fall and remain below $4.00 per MMBtu in any three consecutive month period and will remain suspended until average
Henry Hub natural gas prices are above $4.00 per MMBtu for three consecutive months. The carry terms ensure economic
alignment with our partner in periods of low natural gas prices. Due to the suppressed natural gas price, we did not make any
payments towards the CONSOL Carried Cost Obligation in 2012 and expect the carry to remain suspended in 2013. See Off-
Balance Sheet Arrangements below. See Item 8. Financial Statements and Supplementary Data – Note 3. Acquisitions and
Divestitures and Note 12. Long-Term Debt.
Our financial capacity, coupled with our balanced and diversified portfolio, provides us with flexibility in our investment decisions
including execution of our major development projects and increased exploration activity.
Available Liquidity Information regarding cash and debt balances was as follows:
(millions, except percentages)
Cash and Cash Equivalents
Amount Available to be Borrowed Under Credit Facility (1)
Total Liquidity
Total Debt (2)
Total Shareholders' Equity
Ratio of Debt-to-Book Capital (3)
December 31,
2011
2012
2010
$
$
$
1,387
4,000
5,387
4,123
8,258
$
$
$
1,455
3,000
4,455
4,495
7,265
$
$
$
1,081
1,750
2,831
2,279
6,848
33%
38%
25%
(1) See Credit Facility below.
(2) Total debt includes Aseng FPSO lease obligation and remaining CONSOL installment payments and excludes unamortized debt
discount.
(3) We define our ratio of debt-to-book capital as total debt (which includes long-term debt excluding unamortized discount, the current
portion of long-term debt, and short-term borrowings) divided by the sum of total debt plus shareholders’ equity.
Cash and Cash Equivalents We had approximately $1.4 billion in cash and cash equivalents at December 31, 2012, compared
with approximately $1.5 billion at December 31, 2011. At December 31, 2012 our cash was primarily denominated in US
dollars and invested in money market funds and short-term deposits with major financial institutions. Approximately $1.0
billion of this cash is attributable to our foreign subsidiaries and most would be subject to US income taxes if repatriated. We
currently expect to use a significant amount of cash during 2013 to fund international projects, including the planned
developments in West Africa and the Eastern Mediterranean.
Credit Facility We have an unsecured revolving credit facility that matures on October 14, 2016. The commitment is $4.0
billion through the maturity date of the credit facility. See Financing Activities – Long-Term Debt below.
Derivative Instruments We use various derivative instruments in combination with anticipated crude oil and natural gas sales
to minimize the impact of product price fluctuations and ensure cash flow for future capital needs. Such instruments include
variable to fixed price commodity swaps, two and three-way collars and basis swaps. We have also used derivative instruments
to manage interest rate risk by entering into forward contracts or swap agreements to minimize the impact of interest rate
fluctuations associated with fixed or floating rate borrowings. Current period settlements on derivative instruments impact our
liquidity, since we are either paying cash to, or receiving cash from, our counterparties.
None of our counterparty agreements contain margin requirements. Depending on the rules and definitions adopted by the
CFTC and prudential regulators pursuant to the requirements of the Dodd-Frank Act, we could be required to post significant
amounts of collateral with our dealer counterparties for our derivative transactions. A sudden margin call driven by an increase
in commodity prices would have an immediate negative impact on our business plan, forcing us to divert capital from
exploration, development and production activities. Requirements to post cash collateral could result in negative impacts on our
liquidity and financial flexibility and also cause us to incur additional debt. See Item 1A. Risk Factors – Derivatives regulation
included in current or proposed financial legislation and rulemaking could impede our ability to manage business and
financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices and interest
rates.
85
Commodity derivative instruments are recorded at fair value in our consolidated balance sheets, and changes in fair value are
recorded in earnings in the period in which the change occurs. As of December 31, 2012, the fair value of our commodity
derivative assets was $84 million and the fair value of our commodity derivative liabilities was $10 million (after consideration
of netting clauses within our master agreements). See Item 1A. Risk Factors – Commodity and interest rate hedging
transactions may limit our potential gains and We are exposed to counterparty credit risk as a result of our receivables,
hedging transactions, and cash investments.
See Critical Accounting Policies and Estimates – Derivative Instruments and Hedging Activities, Item 7A. Quantitative and
Qualitative Disclosures About Market Risk, and Item 8. Financial Statements and Supplementary Data – Note 10. Derivative
Instruments and Hedging Activities.
US Fiscal Crisis Congress and the Administration have thus far been unable to resolve the country's long-term fiscal issues,
particularly the debt ceiling and the federal budget deficit. Congress recently passed, and the President signed into law, a bill to
suspend the debt ceiling until May 19, 2013. If the debt ceiling is not raised in a timely manner, the US could default on its debt
and/or experience a reduction in its credit rating, and interest rates could rise. In addition, on March 1, 2013 mandatory across-
the-board spending cuts go into effect, and by late March 2013, a new spending bill must be passed to fund the federal
government.
Congress and the Administration are deeply divided over these issues and there is a lack of consensus as to whether deficit
reductions should come from spending cuts, tax increases or a combination of both. In addition, the government has failed to
address increasing entitlement costs. At this time, substantial uncertainty exists as to whether or how these matters will be
resolved. Certain measures, if enacted too suddenly, could reduce economic growth and increase the risk of a recession.
Actions to address the deficit could lead to measures that could increase the tax expense on oil and gas companies. See Item
1A. Risk Factors - Our operations may be adversely affected by changes in the fiscal regimes and government policies and
regulation of oil and gas development in the countries in which we operate and Failure to resolve long-term US fiscal issues,
primarily the federal budget deficit and the debt ceiling, could have a negative impact on the economy, slowing growth and
reducing demand for our products.
European Debt Crisis The European debt crisis continues to have a negative impact on the European economy, with risks to
the global financial system and overall global economy. Countries have raised taxes and reduced entitlements, but are still
struggling to pay off their debts; and the major bailout fund, the European Stability Mechanism (ESM) has limited lending
capacity. During 2012, Cyprus, a country where we currently have exploration and appraisal activities, became the fifth
eurozone country requesting bailout. Some of the European banks are counterparties in our commodity hedging program and
lenders in our credit facility. If these institutions receive credit downgrades, our internal risk guidelines could preclude further
hedging activities with them. At this time, we believe our current balance sheet and financial flexibility enhance our ability to
react to eurozone events as they unfold. See Item 1A. Risk Factors - Our operations may be adversely affected by the European
debt crisis.
Counterparty Credit Risk We monitor the creditworthiness of our trade creditors, joint venture partners, hedging
counterparties, and financial institutions on an ongoing basis. Some of these entities are not as creditworthy as we are and may
experience credit downgrades or liquidity problems. Counterparty credit downgrades or liquidity problems could result in a
delay in our receiving proceeds from commodity sales, reimbursement of joint venture costs, and potential delays in our major
development projects.
The current uncertain economic and commodity price environment increases the risk of a sudden negative change in liquidity,
which could impair a party's ability to perform under the terms of a contract. We are unable to predict sudden changes in a
party's creditworthiness or ability to perform. Even if we do accurately predict such sudden changes, our ability to negate these
risks may be limited and we could incur significant financial losses.
In addition, nonoperating partners often must obtain financing for their share of capital cost for development projects. For
example, our Eastern Mediterranean partners must obtain financing for their share of significant development expenditures at
Leviathan, offshore Israel, which potentially includes an LNG project and/or major underwater pipeline. In conjunction with
our negotiations with Woodside, we are assisting our current Leviathan partners to obtain appropriate financing for their share
of development costs and considering providing a limited amount of financial backstop to them. A partner's inability to obtain
financing could result in a delay of one of our joint development projects. See Item 1A. Risk Factors - Failure of our partners
to fund their share of development costs or obtain project financing could result in delay or cancellation of future projects, thus
limiting our growth and future cash flows.
Credit enhancements have been obtained from some parties in the form of parental guarantees or letters of credit; however, not
all of our counterparty credit is protected through guarantees or credit support. Nonperformance by a trade creditor, joint
venture partner, hedging counterparty or financial institution could result in significant financial losses.
86
Insurance Recoveries In May 2011, we ended drilling operations at the Leviathan-2 appraisal well location offshore Israel
when we identified water flowing to the sea floor from the wellbore. Drilling did not reach the depth of the targeted gas
intervals discovered in the Leviathan-1 well. The incident was a covered event under our well control insurance. At this time,
we expect to recover the costs from insurance, subject to a deductible. We do not expect any delays in the insurance claim
recovery process to have a significant impact on our cash flows or liquidity. See Item 8. Financial Statements and
Supplementary Data – Note 2. Additional Financial Statement Information.
Accounts Receivable We have accounts receivable from sales of our crude oil, natural gas and NGLs. We also have accounts
receivable from joint venture partners for their share of expenses on joint venture projects for which we are the operator. Some
of these parties are not as creditworthy as we are and may experience liquidity problems. We have obtained credit
enhancements from some parties in the way of parental guarantees or letters of credit, including our largest crude oil purchaser;
however, not all of our trade credit is protected through guarantees or credit support. Nonperformance by a trade creditor or
joint venture partner could result in losses. We currently have no significant collection issues with purchasers or joint venture
partners. See Item 1A. Risk Factors – We are exposed to counterparty credit risk as a result of our receivables, hedging
transactions, and cash investments and Item 8. Financial Statements and Supplementary Data – Note 5. Allowance for
Doubtful Accounts.
Cash Flows
Summary cash flow information is as follows:
(millions)
Total Cash Provided By (Used in)
Operating Activities
Investing Activities
Financing Activities
(Decrease) Increase in Cash and Cash Equivalents
Year Ended December 31,
2012
2011
2010
$
$
$
2,933
(2,527)
(474)
(68) $
2,170
(3,113)
1,317
374
$
$
1,946
(1,779)
(100)
67
Operating Activities Net cash provided by operating activities for 2012 increased $763 million, or 35% as compared with 2011.
Higher liquids sales volumes and slightly higher crude oil prices were offset by decreases in natural gas sales volumes and
prices and increases in production expenses, general and administrative expense and interest expense. See Item 8. Financial
Statements and Supplementary Data – Consolidated Statements of Cash Flows.
Net cash provided by operating activities in 2011 increased $224 million, or 12% as compared with 2010. Sales revenues were
higher due to increases in commodity prices and sales volumes.
Investing Activities The primary use of cash in investing activities is for capital spending for oil and gas properties, and investments
in unconsolidated subsidiaries accounted for by the equity method. These investing activities may be offset by proceeds from
property sales or dispositions.
Capital spending for property, plant and equipment totaled $3.7 billion in 2012, representing an increase of $529 million as
compared with 2011, primarily due to increased major project development activity in the DJ Basin, the Marcellus Shale,
offshore West Africa, and offshore Israel. We also invested $41 million in CONE during 2012. In addition, we received $1.2
billion proceeds from non-core asset divestitures during 2012 as compared with $77 million proceeds, during 2011.
In 2011, our capital spending totaled $3.2 billion, including $596 million spent on the Marcellus Shale asset acquisition,
representing an increase of $847 million as compared with 2010. A significant portion of the spending was related to our major
development projects. We received $77 million total proceeds from asset divestitures.
In 2010, our capital spending totaled $2.3 billion, including $458 million spent on the DJ Basin asset acquisition. We received
$564 million total proceeds from asset divestitures.
Financing Activities Our financing activities include the issuance or repurchase of our common stock, payment of cash
dividends on our common stock, the borrowing of cash and the repayment of borrowings.
In 2012, net cash used in financing activities was $474 million. Funds were provided by cash proceeds from, and tax benefits
related to, the exercise of stock options ($81 million). We used cash to make the first CONSOL installment payment ($328
million), pay dividends on our common stock ($164 million), make principal payments related to the Aseng FPSO capital lease
obligation ($45 million), repurchase shares of our common stock ($13 million), and other ($5 million).
In 2011, net cash provided by financing activities was $1.3 billion. Funds were provided by net cash proceeds from the
issuance of $850 million 6% senior notes ($836 million) and the issuance of $1.0 billion 4.15% senior notes ($992 million).
87
Also, funds were provided by cash proceeds from, and tax benefits related to, the exercise of stock options ($53 million). Funds
were used for net repayments under our revolving credit facility ($350 million). We also used cash to settle an interest rate lock
($40 million), pay dividends on our common stock ($143 million), repurchase shares of our common stock ($17 million), and
other ($14 million).
In 2010, net cash of $100 million was used in financing activities. Funds were provided by cash proceeds from, and tax benefits
related to, the exercise of stock options ($72 million). Funds were used for net repayments under our revolving credit facility
($32 million). We paid cash dividends on our common stock ($127 million), and repurchased shares of our common stock ($13
million).
Acquisition, Capital and Other Exploration Expenditures
Acquisition, Capital and Other Exploration Expenditures Information (on an accrual basis) is as follows:
(millions)
Acquisition, Capital and Exploration Expenditures
Unproved Property Acquisition (1)
Proved Property Acquisition (2)
Exploration
Development
Corporate and Other
Total
Other
Investment in Equity Method Investee (3)
Increase in FPSO Lease Obligation (4)
Year Ended December 31,
2012
2011
2010
$
$
$
$
$
$
96
—
572
2,847
70
3,585
41
—
$
$
$
982
392
493
2,200
196
4,263
69
66
305
352
343
1,520
121
2,641
—
266
(1) Unproved property acquisition cost for 2012 includes $85 million primarily related to additional acreage in the DJ Basin and other
onshore US lease acquisitions, $25 million related to our entry into a farmout agreement offshore Falkland Islands, $28 million in
bonuses paid on deepwater Gulf of Mexico lease blocks acquired in the June 2012 lease sale, $3 million related to our entry into a
license offshore Sierra Leone (West Africa), offset by downward adjustments related to the Marcellus Shale acquisition.
Unproved property acquisition cost for 2011 includes $853 million related to our acquisition of a 50% interest in Marcellus Shale
undeveloped leases, $40 million related to our position offshore Senegal/Guinea-Bissau (the AGC Profond block), $31 million related
to additional acreage in the DJ Basin, and $58 million related to onshore US lease acquisitions.
Unproved property acquisition cost for 2010 includes $146 million related to the DJ Basin asset acquisition, $38 million for
deepwater Gulf of Mexico lease blocks, and the remainder for other onshore US lease acquisitions primarily in Wattenberg.
(2) Proved property acquisition cost includes $386 million related to the Marcellus Shale asset acquisition in 2011 and $352 million
(3)
related to DJ Basin asset acquisition in 2010.
In connection with the Marcellus Shale joint venture, we acquired a 50% interest in CONE which is accounted for using the equity
method. CONE constructs, owns and operates gathering lines and facilities related to the Marcellus Shale development.
(4) Relates to estimated construction progress on the Aseng FSPO, which went into service during the fourth quarter of 2011.
Excluding the impact of the Marcellus Shale acquisition in 2011, total expenditures increased in 2012 as compared with 2011
due to targeted investing in our major development projects located in the DJ Basin, Marcellus Shale, offshore Equatorial
Guinea and offshore Israel. In addition, exploration activity increased.
Total expenditures in 2011 increased as compared with 2010 due to major development project expenditures and the Marcellus
Shale asset acquisition. In addition, exploration activity increased.
Asset Divestitures In 2012, non-core asset divestitures generated cash proceeds of approximately $1.2 billion. In 2011, we
transferred certain assets to the Ecuadorian government for cash proceeds of $73 million. In 2010, we sold certain non-core
assets in the Mid-Continent and Illinois Basin areas for cash proceeds of $552 million.
88
Risk and Insurance Program
Our business is subject to all of the operating risks normally associated with the exploration, production, gathering, processing
and transportation of crude oil and natural gas, including hurricanes, blowouts, well cratering, fire, loss of well control,
mishandling of fluids and chemicals and possible underground migration of hydrocarbons and chemicals, any of which could
result in damage to, or destruction of, crude oil and natural gas wells or formations or production facilities and other property,
environmental pollution, injury to persons, or loss of life. As protection against financial loss resulting from many, but not all of
these operating hazards, we maintain insurance coverage, including certain physical damage, business interruption (loss of
production income), employer's liability, comprehensive general liability and worker's compensation insurance. 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 revise our insurance program accordingly. We have limited or no
insurance coverage for certain risks such as war or political risk. In addition, coverage is generally limited or not available to us
for pollution events that are considered gradual.
In certain international locations (including Israel and Equatorial Guinea) we carry business interruption insurance for loss of
production income arising from physical damage to our facilities caused by fire and natural disasters. The coverage is subject to
customary deductibles, waiting periods and recovery limits.
In Israel, we carry political violence and terrorism coverage in addition to coverages for business risk. Additionally, as being
part of critical national infrastructure, Mari-B and Tamar are included in a special funding coverage under the government of
Israel property tax fund.
In the Gulf of Mexico, we self-insure for windstorm related exposures. Our Gulf of Mexico assets are primarily subsea
operations; therefore, our direct windstorm exposure is limited. In addition, the cost of windstorm insurance continues to be
very expensive and coverage amounts are limited. We believe it is more cost-effective for us to self-insure these assets.
As is customary with industry practice, crude oil and natural gas well owners generally indemnify drilling rig contractors
against certain risks, such as those arising from property and environmental losses, pollution from sources such as oil spills, or
contamination resulting from well blowout or fire or other uncontrolled flow of hydrocarbons. Most of our US and international
drilling contracts contain such indemnification clauses. In addition, crude oil and natural gas well owners typically assume all
costs of well control in the event of an uncontrolled well. We currently carry more than $700 million in insurance protection,
depending on our ownership interest, for potential financial losses occurring as a result of events such as the Deepwater
Horizon Incident. This protection consists of more than $500 million of well control, pollution cleanup and consequential
damages coverage and more than $200 million of additional pollution cleanup and consequential damages coverage, which also
covers third-party personal injury and death.
We have contracts with third-party service providers to perform hydraulic fracturing operations for us. The master service
agreements signed by hydraulic fracturing providers contain indemnification provisions similar to those noted above. Our
liability insurance policies do not contain any specific exclusions for liabilities from hydraulic fracturing operations and we
believe our policies would cover third party claims related to hydraulic fracturing operations and associated legal expenses, in
accordance with, and subject to, the terms of such policies. We do not have insurance for gradual pollution nor do we have
coverage for penalties or fines that may be assessed by a governmental authority.
We expect the future availability and cost of insurance to be impacted by the various catastrophic events and large losses that
insurers have incurred over the past several years. 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, including possible increases in liability caps for claims of damages
from oil spills. We anticipate that ongoing changes in the types of coverage available in the insurance market may result in
lower effective coverages and/or the incurrence of higher premiums to achieve past levels of coverage.
We continue to monitor the legislative and regulatory response to the Deepwater Horizon Incident of 2010 and other recent
international incidents and their impact on the insurance market and our overall risk profile. We anticipate that, at a minimum,
less effective liability coverage will be available at a higher cost. Accordingly, we may adjust our risk and insurance program to
provide protection at insured levels that reflect our perception of the cost of risk relative to frequency and severity of the
exposure.
Our business entails inherent risks. We have a risk assessment program that analyzes safety and environmental hazards and
establishes procedures, work practices, training programs and equipment requirements, including monitoring and maintenance
rules, for continuous improvement. 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.
89
We are a member in Oil Insurance Limited (OIL). OIL is a mutual insurance company which insures property, pollution
liability, control of well and other catastrophic risks. See Contractual Obligations below for a discussion of our theoretical
withdrawal premium liability.
We maintain membership in Clean Gulf Associates (CGA), a nonprofit association of production and pipeline companies
operating in the Gulf of Mexico. See Items 1. and 2. Business and Properties - Oil Spill Response Preparedness.
Financing Activities
Long-Term Debt Our long-term debt totaled $3.8 billion (excluding the Aseng FPSO lease obligation) at December 31, 2012,
with maturities ranging from 2013 to 2097. Our principal source of liquidity is an unsecured revolving credit facility that
matures October 14, 2016. We did not engage in any short-term borrowing arrangements in 2012 or 2011 other than amounts
drawn and repaid under our credit facility for working capital purposes during the normal course of business.
Credit Facility The Credit Facility, after giving effect to the increase in the overall commitment as of September 28, 2012, (i)
provides for an initial commitment of $4.0 billion, (ii) will mature on October 14, 2016, (iii) provides for facility fee rates that
range from 12.5 basis points to 30 basis points per year depending upon our credit rating, (iv) includes sub-facilities for short-
term loans and letters of credit up to an aggregate amount of $500 million under each sub-facility and (v) provides for interest
rates that are based upon the Eurodollar rate plus a margin that ranges from 100 basis points to 145 basis points depending upon
our credit rating.
The Credit Agreement requires that our total debt to capitalization ratio (as defined in the Credit Agreement), 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 Credit Facility and require the immediate
repayment of any outstanding advances under the Credit Facility.
At December 31, 2012, there were no borrowings outstanding under the Credit Facility, leaving $4.0 billion available for use.
We expect to use the Credit Facility to fund our capital investment program, and we periodically borrow amounts under
provision (iv) above for working capital purposes. See Item 8. Financial Statements and Supplementary Data – Note 12. Long-
Term Debt.
The Credit Facility is available for general corporate purposes. Certain lenders that are a party to the Credit Agreement 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.
CONSOL Installment Payments The first of two $328 million annual installment payments was paid on September 30, 2012.
The remaining installment payment has been discounted at our incremental borrowing rate, a discount rate of 1.79%, and is due
on September 30, 2013. See Item 8. Financial Statements and Supplementary Data – Note 12. Long-Term Debt.
Public Debt Offerings We occasionally enter into public debt offerings to increase our liquidity. During 2011, we completed
two underwritten public offerings of $850 million of 6% senior unsecured notes due March 1, 2041 and $1.0 billion of 4.15%
senior unsecured notes due December 15, 2021. Net proceeds were used to repay outstanding indebtedness under our
revolving credit facility, fund our exploration and development programs and for general corporate purposes.
FPSO Lease Obligation We account for our Aseng FPSO lease agreement as a capital lease. We paid $45 million under our
lease obligation in 2012, compared with $3 million in 2011. The Aseng FPSO completed the construction phase and we
commenced production at Aseng in November 2011.
Fixed-Rate Debt Our outstanding fixed-rate debt (excluding the Aseng FPSO lease obligation) totaled approximately $3.8
billion at December 31, 2012. The weighted average interest rate on fixed-rate debt was 5.89%, with maturities ranging from
2013 to 2097. Approximately 14% of our fixed rate debt matures within the next five years. See Item 8. Financial Statements
and Supplementary Data – Note 12. Long-Term Debt.
Interest Rate Locks We occasionally enter into forward contracts or swap agreements to hedge exposure to interest rate risk.
We enter into these transactions in anticipation of public debt offerings, such as the issuance of our 6% senior unsecured notes
in 2011, to effectively fix the cash flows related to interest payments on the anticipated debt issuance. When the debt is issued,
we settle the contracts or swap agreements and amortize remaining amounts from AOCL to interest expense over the terms of
the notes. See Critical Accounting Policies and Estimates – Derivative Instruments and Hedging Activities, Item 7A.
Quantitative and Qualitative Disclosures About Market Risk, and Item 8. Financial Statements and Supplementary Data – Note
10. Derivative Instruments and Hedging Activities.
90
•
offset by:
•
Ratio of Debt-to-Book Capital Our ratio of debt-to-book capital decreased to 33% at December 31, 2012 from 38% at
December 31, 2011. Significant changes in our financial position included the following:
•
$361 million reduction in debt due to the first installment payment to CONSOL as well as payment under our FPSO
lease obligation; and
$1.0 billion increase in shareholders’ equity from current year net income;
$164 million decrease in shareholders’ equity from dividends paid.
Cash Interest Payments We made cash interest payments of $259 million in 2012, $164 million in 2011, and $133 million in
2010.
Exercise of Stock Options Proceeds from the exercise of stock options totaled $56 million in 2012, $38 million in 2011, and
$47 million in 2010. Proceeds received from the exercise of stock options fluctuate primarily based on the number of options
exercised which is influenced by the price at which our common stock trades on the NYSE in relation to the exercise price of
the options issued.
Dividends We paid cash dividends totaling 91 cents per common share in 2012, 80 cents per common share in 2011, and 72
cents per common share in 2010. On January 28, 2013, the Board of Directors declared a quarterly cash dividend of 25 cents
per common share, which will be paid February 25, 2013 to shareholders of record on February 11, 2013. 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.
Common Stock Repurchases We receive shares of our common stock from employees for the payment of withholding taxes
due on the vesting of restricted shares issued under stock-based compensation plans. We received approximately 141,000
shares with a total value of $13 million in 2012, 187,000 shares with a total value of $17 million in 2011, and 168,000 shares
with a total value of $13 million in 2010.
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, 2012, the material off-balance sheet arrangements and transactions that we have entered into included the
CONSOL Carried Cost Obligation, drilling rig contracts, operating lease agreements, and undrawn letters of credit, all of which
are customary in the oil and gas industry.
CONSOL Carried Cost Obligation The CONSOL Carried Cost Obligation represents our agreement to fund up to
approximately $2.1 billion of CONSOL’s future drilling and completion costs. The CONSOL Carried Cost Obligation is
expected to extend over a multi-year period. It is capped at $400 million in each calendar year and will be suspended if average
Henry Hub natural gas prices fall and remain below $4.00 per MMBtu in any three consecutive month period and will remain
suspended until average Henry Hub natural gas prices are above $4.00 per MMBtu for three consecutive months. Therefore,
specific payment dates for the funding of the CONSOL Carried Cost Obligation cannot be determined at this time. The
CONSOL Carried Cost Obligation is currently suspended due to low natural gas prices. Based on the December 31, 2012
Henry Hub natural gas price strip, we forecast the obligation will be suspended through the 2013 fiscal year. See Items 1. and 2.
Business and Properties - Title to Properties.
Other than the off-balance sheet arrangements listed above, we have no transactions, arrangements or other relationships with
unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of or requirements
for capital resources. See Contractual Obligations below for more information regarding off-balance sheet arrangements.
91
Contractual Obligations
The following table summarizes certain contractual obligations that are reflected in the consolidated balance sheets and/or
disclosed in the accompanying notes. The table excludes the CONSOL Carried Cost Obligation noted above as specific
payment dates are unknown. Unless otherwise noted, all amounts are net to our interest.
Obligation
(millions)
Long-Term Debt (1)
Interest Payments (2)
FPSO Lease Payments (3)
Drilling and Equipment Obligations (4)
United States
International
Purchase Obligations (5)
Transportation and Gathering (6)
Operating Lease Obligations (7)
Other Liabilities (8)
Total
2013
2014 and
2015
2016 and
2017
2018 and
beyond
$
$
3,812
3,249
413
140
420
646
731
543
$
328
229
72
84
164
491
81
47
200
419
142
56
171
139
164
94
$
— $
417
90
3,284
2,184
109
—
85
16
175
100
12
—
895
$
—
—
—
311
302
247
—
6,437
Asset Retirement Obligations (9)
Commodity Derivative Instruments (10)
Total Contractual Obligations
402
10
10,366
$
$
69
7
1,572
$
74
3
1,462
$
(1) Long-term debt excludes our Aseng FPSO lease obligation. See Item 8. Financial Statements and Supplementary Data
(2)
– Note 12. Long-Term Debt.
Interest payments are based on the total debt balance, scheduled maturities and interest rates in effect at December 31,
2012. See Item 8. Financial Statements and Supplementary Data – Note 12. Long-Term Debt.
(3) Annual lease payments, net to our interest, exclude regular maintenance and operational costs. See Item 8. Financial
Statements and Supplementary Data – Note 12. Long-Term Debt.
(4) Drilling and equipment obligations represent contractual agreements with third-party service providers to procure
drilling rigs and other related equipment for exploratory and development drilling activities. See Item 8. Financial
Statements and Supplementary Data – Note 20. Commitments and Contingencies.
(5) Purchase obligations represent 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 Item 8. Financial Statements and Supplementary
Data – Note 20. Commitments and Contingencies.
(6) Transportation and gathering obligations represent minimum charges for firm transportation and gathering
agreements. See Item 8. Financial Statements and Supplementary Data – Note 20. Commitments and Contingencies.
(7) 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. See Item 8. Financial
Statements and Supplementary Data – Note 20. Commitments and Contingencies.
(8) The table excludes deferred compensation liabilities of $229 million and accrued benefit costs of $116 million as
specific payment dates are unknown. See Item 8. Financial Statements and Supplementary Data – Note 14. Stock-
Based and Other Compensation Plans.
(9) Asset retirement obligations are discounted. See Item 8. Financial Statements and Supplementary Data – Note 11.
Asset Retirement Obligations.
(10) Amount represents open commodity derivative instruments that were in a net payable position with the counterparty at
December 31, 2012. Our remaining commodity derivative instruments were in a net receivable position at December
31, 2012. See Item 8. Financial Statements and Supplementary Data – Note 10. Derivative Instruments and Hedging
Activities.
As of December 31, 2012, we accrued approximately $22 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.
92
In addition, in the ordinary course of business, we maintain letters of credit with a variety of banks in support of certain
performance obligations of our subsidiaries. Outstanding letters of credit totaled approximately $68 million at December 31,
2012.
Other
Income Taxes We made cash payments for income taxes, net of refunds, of $168 million in 2012, $288 million in 2011, and
$173 million in 2010.
Contingencies Payments to settle legal proceedings totaled approximately $12 million in 2012, $1 million in 2011, and $7
million in 2010. We regularly analyze current information and accrue for probable liabilities on the disposition of certain
matters, as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded
when it is probable that a liability has been incurred and the amount can be reasonably estimated.
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 All of the reserves data in this Form 10-K are estimates. Estimates of our crude oil and natural gas reserves are
prepared by our qualified petroleum engineers in accordance with guidelines established by the SEC, including rule revisions
designed to modernize the oil and gas company reserves reporting requirements, which we implemented effective December
31, 2009. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas.
There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Uncertainties
include the projection of future production rates and the expected timing of development expenditures. 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 and natural gas that are ultimately recovered. In
addition, economic producibility of reserves is dependent on the oil and gas prices used in the reserves estimate. Our reserves
estimates are based on 12-month average commodity prices, unless contractual arrangements designate the price to be used, in
accordance with SEC rules. However, oil and gas prices are volatile and, as a result, our reserves estimates will change in the
future.
Estimates of proved crude oil and natural gas 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
properties exceeds fair value and could result in an impairment charge, which would reduce earnings. In addition, a decline in
estimates of proved reserves could prompt a goodwill impairment analysis. See Item 8. Financial Statements and
Supplementary Data – Supplemental Oil and Gas Information (Unaudited).
Oil and Gas Properties We account for crude oil and natural gas properties under the successful efforts method of
accounting. Under the successful efforts method, costs to acquire mineral interests in crude oil and natural gas properties, drill
and equip exploratory wells that find commercial quantities of proved reserves, and drill and equip development wells are
capitalized. Proved property acquisition costs are amortized to expense by the unit-of-production method on a field-by-field
basis based on total proved crude oil and natural gas reserves as estimated by our qualified petroleum engineers. Costs to drill
and equip exploratory wells that find proved reserves and drill and equip development wells are also amortized to expense by
the unit-of-production method on a field-by-field basis. These costs, along with support equipment and facilities, are amortized
based on proved developed crude oil and natural gas reserves. 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. Application of the successful efforts method results in the expensing of certain costs including geological and
geophysical costs, exploratory dry holes and delay rentals, during the periods the costs are incurred.
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. 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.
93
Exploratory Well Costs In accordance with the successful efforts method of accounting, the 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 the well has 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 deepwater Gulf of Mexico or international projects, it may take several years to evaluate the future
potential of the exploration 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 submitting requests for permits and approvals and believe they will be
obtained.
Management assesses the status of suspended exploratory well costs on a quarterly basis. These costs may be charged to
exploration expense in future periods if we decide not to pursue additional exploratory or development activities. This occurred
in 2012 when we decided not to pursue development of our Deep Blue exploratory well in the deepwater Gulf of Mexico.
Although hydrocarbons were found in both the initial exploration well and subsequent sidetrack, we and our partners decided
not to proceed with additional appraisal activities. At December 31, 2012, the balance of property, plant and equipment
included $900 million of suspended exploratory well costs, $545 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 exploration wells. See Item 8. Financial Statements and Supplementary Data – Note 7. Capitalized
Exploratory Well Costs.
Impairment of Proved Oil and Gas Properties and Other Investments We assess proved crude oil and natural gas
properties and other investments for possible impairment at least semi-annually, at year-end and mid-year or 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 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 cash flows are based on
management’s expectations for the future and include estimates of crude oil and natural gas reserves and future commodity
prices, revenues and operating and development costs. Negative revisions in estimates of reserves quantities or expectations of
falling commodity prices or rising operating or development costs could result in a reduction in undiscounted future cash flows
and could indicate property impairment.
During 2012, we assessed proved properties for possible impairment due to lower commodity prices, performance issues, and/
or changes in our intended use. Certain assets were determined to be impaired and were written down to their estimated fair
values under a discounted cash flow model. The discounted cash flow model included management’s estimates of future oil and
gas production; commodity prices based on forward commodity price curves at the date of the estimate; operating and
development costs, and discount rates.
We recorded total pre-tax (non-cash) asset impairment charges of $104 million in 2012, $757 million in 2011 and $144 million
in 2010 for proved oil and gas properties and other investments. See Item 8. Financial Statements and Supplementary Data –
Note 4. Asset Impairments.
Impairment of Unproved Oil and Gas Properties We also perform assessments of individually significant unproved crude
oil and natural gas 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 values to a significant unproved property (probable and/or possible reserves) as the result of a
business combination or other purchase of proved and unproved properties, we use a future cash flow 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 extract 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 as likely as not 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.
94
Negative revisions in estimated reserves quantities, reductions in commodity prices, or increases in estimated costs could cause
a reduction in the value of an unproved property and, therefore, could also cause a reduction in the carrying amount of the
property. 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 for determining the amount of the
impairment loss to record. The estimated prices used in the cash flow analysis are determined by management based on forward
commodity price curves as of the date of the estimate, adjusted for average historical location and quality differentials.
Estimates of cash flows related to probable and possible reserves are reduced by additional risk-weighting factors.
Due to the volatility of crude oil and natural gas prices, these cash flow estimates are inherently imprecise. Management’s
assessment of the results of exploration activities, availability of funds for future activities and the current and projected
political climate in areas in which we operate also impact the amounts and timing of impairment provisions.
We assessed the recoverability of our significant unproved oil and gas properties periodically during the years ended
December 31, 2012, 2011 and 2010 and determined there were no impairments. See Item 8. Financial Statements and
Supplementary Data – Note 4. Asset Impairments.
Purchase Price Allocations We occasionally acquire assets and assume liabilities in transactions accounted for as business
combinations, such as our DJ Basin asset acquisition in 2010. 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 tax bases of assets
and liabilities. Any excess of the purchase price over amounts assigned to assets and liabilities is recorded as goodwill. Any
excess of amounts assigned to assets and liabilities over the purchase price is recorded as a gain on bargain purchase. 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.
In estimating the fair values of assets acquired and liabilities assumed in a business combination, we make various
assumptions. The most significant assumptions relate to the estimated fair values assigned to proved and unproved crude oil
and natural gas properties. If sufficient market data is not available regarding the fair values of proved and unproved properties,
we must prepare estimates. To estimate the fair values of these properties, we prepare estimates of crude oil and natural gas
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 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.
Estimated fair values assigned to assets acquired 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. Acquisitions and Divestitures.
Goodwill As of December 31, 2012, the consolidated balance sheet included $635 million of goodwill, all of which has been
assigned to the US reporting unit. Goodwill is not amortized to earnings but is assessed, at least annually, for impairment at the
reporting unit level. We conduct a qualitative goodwill impairment assessment as of December 31 of each year by examining
relevant events and circumstances which could have a negative impact on our goodwill such as macroeconomic conditions,
industry and market conditions, cost factors that have a negative effect on earnings and cash flows, overall financial
performance, segment dispositions and acquisitions, and other relevant entity-specific events.
After assessing the totality of events and circumstances for the qualitative impairment assessment at December 31, 2012, we
determined that performing the two-step goodwill impairment test was unnecessary, and no goodwill impairment was
recognized.
95
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 US 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 our 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.
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 US reporting unit, we use a combination
of the income approach and the market approach.
Under the income approach, the fair value of the US 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, 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 and natural
gas 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 company based weighted average cost of capital.
Under the market approach, we estimate the value of the US reporting unit by comparison to similar businesses whose
securities are actively traded in the public market. This requires management to make certain judgments about the selection of
comparable companies and/or comparable recent company and asset transactions and transaction premiums. We use a peer
company 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 it more accurately compares companies using successful efforts and full cost accounting methods,
both of which are in our peer group.
Although we base the fair value estimate of the US 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 global recession, commodity prices may stay depressed or decline further, thereby causing the fair value of the US
reporting unit to decline, which could result in an impairment of goodwill. When we dispose of a reporting unit or a portion of
a reporting unit that constitutes a business, we 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 is based on the relative fair value of the business to be disposed of and the portion of the
reporting unit that will be retained. During 2012, we sold certain non-core onshore US assets. Goodwill allocated to these
assets sold totaled $61 million. See Item 8. Financial Statements and Supplementary Data – Note 9. Goodwill.
Derivative Instruments and Hedging Activities In order to mitigate the effects of commodity price uncertainty and increase
cash flow predictability relating to the marketing of our crude oil and natural gas, we enter into crude oil and natural gas price
hedging arrangements with respect to a portion of our expected production. In addition, we have used derivative instruments in
connection with acquisitions and certain price-sensitive projects. Management exercises significant judgment in determining
the types of instruments to be used, production volumes to be hedged, prices at which to hedge and the counterparties’
creditworthiness. All commodity derivative instruments are reflected at fair value in our consolidated balance sheets.
Our open commodity derivative instruments were in a net receivable position with a fair value of $74 million at December 31,
2012. In order to determine the fair value at the end of each reporting period, we compute discounted cash flows for the
duration of each commodity derivative instrument using the terms of the related contract. Inputs consist of published forward
commodity price curves as of the date of the estimate. We compare these prices to the price parameters contained in our hedge
contracts to determine estimated future cash inflows or outflows. We then discount the cash inflows or outflows using a
combination of published LIBOR rates, Eurodollar futures rates and interest swap rates. The fair values of our commodity
96
derivative assets and liabilities include a measure of credit risk based on current published credit default swap rates. In addition,
for collars, we estimate the option value of the contract floors and ceilings using an option pricing model which takes into
account market volatility, market prices and contract parameters.
Changes in the fair values of our commodity derivative instruments have a significant impact on our net income because we
follow mark-to-market accounting and recognize all gains and losses on such instruments in earnings in the period in which
they occur. For the year ended December 31, 2012, we reported a $75 million mark-to-market gain on commodity derivative
instruments.
We also use derivative instruments to manage interest rate risk by entering into forward contracts or swap agreements to
minimize the impact of interest rate fluctuations associated with fixed or floating rate borrowings. We designate these as cash
flow hedges and all changes in fair value are reported in AOCL, to the extent the hedge is effective, until the forecasted
transaction occurs, at which time they are recorded as adjustments to interest expense over the term of the related debt issuance.
In order to determine the fair value at the end of each reporting period, we compute discounted cash flows for the duration of
the instrument using the terms of the related contract. Inputs consist of published interest rate yield curves as of the date of the
estimate and a measure of our own nonperformance risk, based on the current published credit default swap rates.
We compare our estimates of the fair values of our commodity and interest rate derivative instruments with those provided by
our counterparties. There have been no significant differences. See Item 7A. Quantitative and Qualitative Disclosures About
Market Risk – Commodity Price Risk and Interest Rate Risk and Item 8. Financial Statements and Supplementary Data – Note
10. Derivative Instruments and Hedging Activities and Note 15. Fair Value Measurements and Disclosures.
Asset Retirement Obligations Our asset retirement obligations (ARO) 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 and the obligation can reasonably be estimated. The associated asset retirement cost is capitalized as part of
the carrying cost of the oil and gas asset. 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 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. Asset retirement obligations totaled $402 million at December 31, 2012. See Item 8. Financial Statements and
Supplementary Data – Note 11. Asset Retirement Obligations.
Income Tax Expense and Deferred Tax Assets 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, 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. Any increases or decreases in a deferred tax asset valuation allowance would impact net
income through offsetting changes in income tax expense. During 2012 and as a result of tax planning strategies, we reversed a
$57 million deferred tax asset for future foreign tax credits from our foreign branch operations along with the corresponding
valuation allowance. In 2012, we also established a valuation allowance on our available foreign tax credit carried forward of
$38 million with a net increase in deferred income tax expense.
97
As of December 31, 2012, the accumulated undistributed earnings of our foreign subsidiaries that have been permanently
reinvested totaled approximately $2.6 billion. No US taxes have been recorded on these earnings. Management must consider
numerous factors in determining timing and amounts of possible future distribution of these earnings to the parent company
and whether a US deferred tax liability should be recorded for these earnings. These factors include the future operating and
capital requirements of both the parent company and the subsidiaries, remittance restrictions imposed by foreign governments
or financial agreements and tax consequences of the remittance, including possible application of US foreign tax credits and
limitations on foreign tax credits that may be imposed by the Internal Revenue Service (IRS) or IRS regulations.
We currently intend to use a significant portion of our international cash to fund international projects, including the
development of our properties in West Africa and the Eastern Mediterranean. However, we estimate that a repatriation of $1.0
billion as of December 31, 2012, if we had elected not to use the cash to fund international development, would have had a net
cash tax impact of approximately $100 million. This amount is net of estimated foreign tax credits. See Item 8. Financial
Statements and Supplementary Data – Note 13. 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 market risk in the normal course of business
operations, and the volatility of crude oil and natural gas prices continues to impact the oil and gas industry. Due to the
volatility of crude oil and natural gas prices, we continue to use derivative instruments as a means of managing our exposure to
price changes.
At December 31, 2012, we had entered into variable to fixed price commodity swaps, collars and basis swaps related to crude
oil and natural gas sales. 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 asset position with a fair value of $74 million.
Based on the December 31, 2012 published commodity futures price curves for the underlying commodities, a hypothetical
price increase of $1.00 per Bbl for crude oil would decrease the fair value of our net commodity derivative asset by
approximately $20 million. A hypothetical price increase of $0.10 per MMBtu for natural gas would decrease the fair value of
our net commodity derivative asset by approximately $8 million. Our derivative instruments 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 cash settled
at the time of election. See Item 8. Financial Statements and Supplementary Data – Note 10. Derivative Instruments and
Hedging Activities.
Interest Rate Risk
Changes in interest rates affect the amount of interest we pay on borrowings under our revolving credit facility and the amount
of interest we earn on our short-term investments.
At December 31, 2012, we had approximately $3.8 billion (excluding the Aseng FPSO lease obligation) of long-term debt
outstanding. All debt outstanding was fixed-rate debt with a weighted average interest rate of 5.89%. 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 12. Long-Term Debt.
We occasionally enter into interest rate derivative instruments such as forward contracts or swap agreements to hedge exposure
to interest rate risk. Changes in fair value of interest rate derivative instruments used as cash flow hedges are reported in
AOCL, to the extent the hedge is effective, until the forecasted transaction occurs, at which time they are recorded as
adjustments to interest expense. At December 31, 2012, AOCL included $25 million, net of tax, related to interest rate
derivative instruments. This amount is currently being reclassified to earnings as adjustments to interest expense over the terms
of our 5¼% senior notes due April 15, 2014 and 6% senior notes due March 1, 2041. See Item 8. Financial Statements and
Supplementary Data – Note 10. Derivative Instruments and Hedging Activities.
We are also exposed to interest rate risk related to our interest-bearing cash and cash equivalents balances. As of December 31,
2012, our cash and cash equivalents totaled approximately $1.4 billion, approximately 56% of which was invested in money
market funds and short-term investments with major financial institutions. A hypothetical 25 basis point change in the floating
interest rates applicable to the amount invested as of December 31, 2012 would result in a change in annual interest income of
approximately $2 million.
98
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, such as foreign
deferred tax liabilities in certain foreign tax jurisdictions, are denominated in a foreign currency. 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 transaction losses from continuing operations were $1 million for 2012, compared with a loss of $8 million for 2011 and a
gain of $3 million for 2010. The losses were primarily related to the changes in exchange rates between the US dollar and
Israeli new shekel. 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.
99
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....................................................................................
101
Report of Independent Registered Public Accounting Firm (Financial Statements) .............................................................
102
Report of Independent Registered Public Accounting Firm (Internal Control over Financial Reporting) ............................
103
Consolidated Statements of Operations for Each of the Years in the Three-year Period Ended December 31, 2012 ...........
104
Consolidated Statements of Comprehensive Income for Each of the Years
in the Three-year Period Ended December 31, 2012 .............................................................................................................
105
Consolidated Balance Sheets as of December 31, 2012 and 2011.........................................................................................
106
Consolidated Statements of Cash Flows for Each of the Years in the Three-Year Period Ended December 31, 2012 .........
107
Consolidated Statements of Shareholders’ Equity for Each of the Years
in the Three-year Period Ended December 31, 2012 .............................................................................................................
108
Notes to Consolidated Financial Statements
Note 1. Summary of Significant Accounting Policies .........................................................................................................
Note 2. Additional Financial Statement Information...........................................................................................................
Note 3. Acquisitions and Divestitures..................................................................................................................................
Note 4. Asset Impairments...................................................................................................................................................
Note 5. Allowance for Doubtful Accounts...........................................................................................................................
Note 6. Inventories...............................................................................................................................................................
Note 7. Capitalized Exploratory Well Costs ........................................................................................................................
Note 8. Equity Method Investments ....................................................................................................................................
Note 9. Goodwill..................................................................................................................................................................
Note 10. Derivative Instruments and Hedging Activities ....................................................................................................
Note 11. Asset Retirement Obligations................................................................................................................................
Note 12. Long-Term Debt....................................................................................................................................................
Note 13. Income Taxes.........................................................................................................................................................
Note 14. Stock-Based and Other Compensation Plans........................................................................................................
Note 15. Fair Value Measurements and Disclosures ...........................................................................................................
Note 16. Earnings Per Share ................................................................................................................................................
Note 17. Segment Information.............................................................................................................................................
Note 18. Concentration of Risk ...........................................................................................................................................
Note 19. Additional Shareholders’ Equity Information .......................................................................................................
Note 20. Commitments and Contingencies .........................................................................................................................
109
114
116
119
120
120
121
123
124
124
128
129
130
134
137
140
140
142
143
143
Supplemental Oil and Gas Information (Unaudited) .............................................................................................................
145
Supplemental Quarterly Financial Information (Unaudited) .................................................................................................
157
100
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, 2012, 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, 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, 2012, based on those
criteria. Management included in its assessment of internal control over financial reporting all consolidated entities.
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, 2012 which is included herein.
Noble Energy, Inc.
101
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Noble Energy, Inc.:
We have audited the accompanying consolidated balance sheets of Noble Energy, Inc. and subsidiaries as of December 31,
2012 and 2011, and the related consolidated statements of operations, comprehensive income, shareholders' equity, and cash
flows for each of the years in the three-year period ended December 31, 2012. 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 conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial
position of Noble Energy, Inc. and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their
cash flows for each of the years in the three-year period ended December 31, 2012, 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),
Noble Energy, Inc.'s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal
Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO),
and our report dated February 7, 2013 expressed an unqualified opinion on the effectiveness of the Company's internal control
over financial reporting.
Houston, Texas
February 7, 2013
/s/ KPMG LLP
102
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Noble Energy, Inc.:
We have audited Noble Energy, Inc.'s internal control over financial reporting as of December 31, 2012, based on criteria
established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO). Noble Energy, Inc.'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 Control over Financial Reporting. Our responsibility is to express an opinion on the
Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).
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 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.
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.
In our opinion, Noble Energy, Inc. maintained, in all material respects, effective internal control over financial reporting as of
December 31, 2012, based on criteria established in Internal Control - Integrated Framework 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),
the consolidated balance sheets of Noble Energy, Inc. and subsidiaries as of December 31, 2012 and 2011, and the related
consolidated statements of operations, comprehensive income, shareholders' equity, and cash flows for each of the years in the
three-year period ended December 31, 2012, and our report dated February 7, 2013 expressed an unqualified opinion on those
consolidated financial statements.
Houston, Texas
February 7, 2013
/s/ KPMG LLP
103
Noble Energy, Inc.
Consolidated Statements of Operations
(millions, except per share amounts)
Year Ended December 31,
2012
2011
2010
Revenues
Oil, Gas and NGL Sales
Income from Equity Method Investees
Other Revenues
Total Revenues
Costs and Expenses
Production Expense
Exploration Expense
Depreciation, Depletion and Amortization
General and Administrative
Gain on Divestitures
Asset Impairments
Other Operating (Income) Expense, Net
Total Operating Expenses
Operating Income
Other (Income) Expense
Gain on Commodity Derivative Instruments
Interest, Net of Amount Capitalized
Other Non-Operating (Income) Expense, Net
Total Other (Income) Expense
Income from Continuing Operations Before Income Taxes
Income Tax Provision
Income from Continuing Operations
Discontinued Operations, Net of Tax
Net Income
Earnings Per Share, Basic
Income from Continuing Operations
Discontinued Operations, Net of Tax
Net Income
Earnings Per Share, Diluted
Income from Continuing Operations
Discontinued Operations, Net of Tax
Net Income
Weighted Average Number of Shares Outstanding
Basic
Diluted
$
4,037
$
3,179
$
186
—
4,223
673
409
1,370
384
(154)
104
25
2,811
1,412
(75)
125
6
56
1,356
391
965
62
193
32
3,404
558
277
878
339
(25)
757
86
2,870
534
(42)
65
9
32
502
90
412
41
$
$
$
$
$
1,027
$
453
$
$
$
$
$
5.43
0.34
5.77
5.37
0.34
5.71
178
180
$
$
$
$
2.34
0.23
2.57
2.31
0.23
2.54
176
179
2,523
118
72
2,713
515
242
819
273
(113)
144
64
1,944
769
(157)
72
6
(79)
848
217
631
94
725
3.61
0.54
4.15
3.56
0.54
4.10
175
177
The accompanying notes are an integral part of these financial statements.
104
Noble Energy, Inc.
Consolidated Statements of Comprehensive Income
(millions)
Net Income
Other Items of Comprehensive Income (Loss)
Oil and Gas Cash Flow Hedges
Realized Losses Reclassified Into Earnings
Less Tax Benefit
Interest Rate Cash Flow Hedges
Unrealized Change in Fair Value
Less Tax Provision (Benefit)
Net Change in Pension and Other
Less Tax Benefit
Other Comprehensive Income
Comprehensive Income
Year Ended December 31,
2012
2011
2010
$
1,027
$
453
$
725
—
—
—
—
(20)
7
(13)
1,014
$
—
—
23
(8)
(17)
6
4
$
457
$
20
(8)
(63)
22
—
—
(29)
696
The accompanying notes are an integral part of these financial statements.
105
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
Deferred Income Taxes, Noncurrent
Other Noncurrent Liabilities
Total Liabilities
Commitments and Contingencies
Shareholders’ Equity
Preferred Stock - Par Value $1.00 per share; 4 Million Shares Authorized, None Issued
Common Stock - Par Value $0.01 and $3.33 1/3 per share; 500 Million and 250 Million
Shares Authorized; 198 Million and 197 Million Shares Issued, Respectively
Additional Paid in Capital
Accumulated Other Comprehensive Loss
Treasury Stock, at Cost; 19 Million Shares
Retained Earnings
Total Shareholders’ Equity
December 31,
2012
December 31,
2011
$
1,387
$
964
420
2,771
19,496
344
19,840
(6,289)
13,551
635
597
1,455
783
180
2,418
19,057
294
19,351
(6,569)
12,782
696
548
$
$
17,554
$
16,444
1,508
$
1,024
2,532
3,736
2,218
810
9,296
—
2
3,304
(113)
(648)
5,713
8,258
1,343
925
2,268
4,100
2,059
752
9,179
—
656
2,497
(100)
(638)
4,850
7,265
Total Liabilities and Shareholders’ Equity
$
17,554
$
16,444
The accompanying notes are an integral part of these financial statements.
106
Noble Energy, Inc.
Consolidated Statements of Cash Flows
(millions)
Cash Flows From Operating Activities
Net Income
Adjustments to Reconcile Net Income to Net Cash Provided by
Operating Activities
Depreciation, Depletion and Amortization
Asset Impairments
Dry Hole Cost
Deferred Income Taxes
Dividends (Income) from Equity Method Investees, Net
Unrealized (Gain) Loss on Commodity Derivative Instruments
Gain on Divestitures
Stock Based Compensation
Other Adjustments for Noncash Items Included in Income
Changes in Operating Assets and Liabilities
(Increase) in Accounts Receivable
(Increase) Decrease in Other Current Assets
Increase in Accounts Payable
Increase in Current Income Taxes Payable
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
Marcellus Shale Asset Acquisition
DJ Basin Asset Acquisition
Additions to Equity Method Investments
Proceeds from Divestitures
Other
Net Cash Used in Investing Activities
Cash Flows From Financing Activities
Exercise of Stock Options
Excess Tax Benefits from Stock-Based Awards
Dividends Paid, Common Stock
Purchase of Treasury Stock
Proceeds from Credit Facilities
Repayment of Credit Facilities
Repayment of CONSOL Installment Loan
Proceeds from Issuance of Senior Long-Term Debt, Net
Settlement of Interest Rate Derivative Instrument
Repayment of Capital Lease Obligation
Other
Net Cash Provided By (Used in) Financing Activities
Increase (Decrease) in Cash and Cash Equivalents
Cash and Cash Equivalents at Beginning of Period
Cash and Cash Equivalents at End of Period
Year Ended December 31,
2012
2011
2010
$
1,027
$
453
$
725
1,403
104
182
109
7
(109)
(72)
65
83
(130)
(45)
237
64
18
(10)
2,933
(3,650)
—
—
(41)
1,160
4
(2,527)
56
25
(164)
(13)
150
(150)
(328)
—
—
(45)
(5)
(474)
(68)
1,455
1,387
$
965
759
105
(81)
30
22
(25)
58
40
(249)
7
3
37
38
8
2,170
(2,594)
(527)
—
(69)
77
—
(3,113)
38
15
(143)
(17)
520
(870)
—
1,828
(40)
(3)
(11)
1,317
374
1,081
1,455
$
883
144
58
71
21
(70)
(113)
54
15
(86)
18
234
31
3
(42)
1,946
(1,885)
—
(458)
—
564
—
(1,779)
47
25
(127)
(13)
760
(792)
—
—
—
—
—
(100)
67
1,014
1,081
$
The accompanying notes are an integral part of these financial statements.
107
Noble Energy, Inc.
Consolidated Statements of Shareholders' Equity
(millions)
Common
Stock
Additional
Paid in
Capital
Accumulated
Other
Comprehensive
Loss
Treasury
Stock at
Cost
Retained
Earnings
Total
Shareholders'
Equity
December 31, 2009
$
645
$
2,260
$
Net Income
Stock-based Compensation Expense
Exercise of Stock Options
Tax Benefits Related to Exercise of
Stock Options
Cash Dividends (72 cents per share)
Purchase of Treasury Stock
Rabbi Trust Shares Sold
Oil and Gas Cash Flow Hedges
Realized Amounts Reclassified
Into Earnings
Interest Rate Cash Flow Hedges
Unrealized Change in Fair Value
Net Change in Other
December 31, 2010
Net Income
Stock-based Compensation Expense
Exercise of Stock Options
Tax Benefits Related to Exercise of
Stock Options
Cash Dividends (80 cents per share)
Purchase of Treasury Stock
Rabbi Trust Shares Sold
Interest Rate Cash Flow Hedges
Unrealized Change in Fair Value
Net Change in Other
December 31, 2011
Net Income
Stock-based Compensation Expense
Exercise of Stock Options
Tax Benefits Related to Exercise of
Stock Options
Cash Dividends (91 cents per share)
Purchase of Treasury Stock
Rabbi Trust Shares Sold
—
—
5
—
—
—
—
—
—
1
$
651
$
—
—
3
—
—
—
—
—
2
$
656
$
—
—
2
—
—
—
—
Change in Par Value
Net Change in Other
December 31, 2012
(656)
—
2
$
—
54
42
25
—
—
5
—
—
(1)
2,385
$
—
58
35
15
—
—
6
—
(2)
2,497
$
—
65
54
25
—
—
7
656
—
$
3,304
$
The accompanying notes are an integral part of these financial statements.
108
(75) $
—
(615) $
—
—
—
—
—
—
—
12
(41)
—
(104) $
—
—
—
—
—
—
—
15
(11)
(100) $
—
—
—
—
—
—
—
—
(13)
(113) $
—
—
—
—
(13)
4
—
—
—
(624) $
—
—
—
—
—
(17)
3
—
—
(638) $
—
—
—
—
—
(13)
3
—
—
(648) $
3,942
$
725
—
—
—
(127)
—
—
—
—
—
4,540
$
453
—
—
—
(143)
—
—
—
—
4,850
$
1,027
—
—
—
(164)
—
—
—
—
5,713
$
6,157
725
54
47
25
(127)
(13)
9
12
(41)
—
6,848
453
58
38
15
(143)
(17)
9
15
(11)
7,265
1,027
65
56
25
(164)
(13)
10
—
(13)
8,258
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 oil and
gas exploration and production. Our core operating areas are onshore US (DJ Basin and Marcellus Shale), deepwater Gulf of
Mexico, offshore West Africa and offshore Eastern Mediterranean.
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. We use the equity method of accounting for investments in entities that we do not control but over which we exert
significant influence. We carry equity method investments at our share of net assets of the equity investees plus our loans and
advances. 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. See Note 8. Equity Method Investments. All significant
intercompany balances and transactions have been eliminated upon consolidation.
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 and natural gas reserves are the most significant of our estimates. All the reserves data
included in this Form 10-K are estimates. Reservoir engineering is a subjective process of estimating underground
accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude
oil and natural gas 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 and natural gas 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 Vice President - Strategic Planning, Environmental
Analysis & Reserves 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 property, plant and equipment, goodwill and
asset retirement obligations, 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. Further decline in natural gas prices or a significant
decline in crude oil 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 and/or goodwill 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).
Reclassification Certain reclassifications have been made to the 2011 and 2010 consolidated financial statements to reflect the
operations of our North Sea geographical segment as discontinued, as well as to conform to the 2012 presentation. These
reclassifications were not material to the financial statements.
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 15. 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. See Note 5. Allowance for
Doubtful Accounts.
109
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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 average cost or market. The
cost of crude oil inventory includes production costs and DD&A of oil and gas properties. See Note 6. Inventories.
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 and natural gas 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 five to 14
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. Repairs and maintenance are expensed as incurred.
Proved Property Impairment We review individually significant proved oil and gas properties and other long-lived assets for
impairment at least semi-annually, at year-end and mid-year, or quarterly when events and circumstances indicate a decline in
the recoverability of the carrying values of such properties, such as a negative revision of reserves estimates or sustained
decrease in commodity prices. We estimate future cash flows expected in connection with the properties and compare such
future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable. When the
carrying amount of a property exceeds its estimated undiscounted future 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 oil and gas production, commodity prices based on published
forward commodity price curves as of the date of the estimate, operating and development costs, and a risk-adjusted discount
rate.
We recorded proved property impairment charges in 2012, 2011, and 2010. It is likely that other proved oil and gas properties
could become impaired in the future if commodity prices decline. See Note 4. Asset Impairments.
Unproved Property Impairment Our unproved properties consist of leasehold costs and allocated value to probable and
possible reserves 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 and natural gas reserves, future commodity
prices and future costs to extract 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
based on our experience of successful drilling and average holding period. It is reasonably possible that unproved oil and gas
properties could become impaired in the future if commodity prices decline. See Note 4. Asset Impairments.
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 and natural gas 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. See Note 3. Acquisitions and Divestitures.
Assets Held for Sale We occasionally market non-core oil and gas properties. At the end of each reporting period, we evaluate
our 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. See Note 3. Acquisitions and Divestitures.
110
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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 deepwater Gulf of Mexico or international projects, it may take us more than one year to evaluate the future
potential of the exploration 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 7. Capitalized Exploratory Well Costs.
Other Property Other property includes automobiles, trucks, airplanes, office furniture, computer equipment and other fixed
assets such as building 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 ten years.
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 the 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 $151 million in 2012, $132
million in 2011, and $67 million in 2010.
Asset Retirement Obligations Asset retirement obligations 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 determined at current costs and is inflated into future dollars using an
inflation rate that is based on the consumer price index. The future projected cash flows are then discounted to their present
value using a 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 our DD&A expense in the statement 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 11. Asset Retirement Obligations.
Goodwill Goodwill represents the excess of the cost of an acquired entity over the net amounts assigned to assets acquired and
liabilities assumed. Goodwill is not amortized to earnings but is qualitatively assessed annually in the fourth quarter. 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. No goodwill impairment was indicated at
December 31, 2012. However, it is possible that goodwill could become impaired in the future if commodity prices or other
economic factors become less favorable.
When we dispose of a reporting unit or a portion of a reporting unit that constitutes a business, we 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 is 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 Note 9. Goodwill.
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. Changes in the derivative instrument’s fair value are recognized currently in earnings, unless the derivative instrument
has been designated as a cash flow hedge and specific cash flow hedge accounting criteria are met. Under cash flow hedge
accounting, unrealized gains and losses are reflected in shareholders’ equity as accumulated other comprehensive loss (AOCL)
until the forecasted transaction occurs. The derivative’s gains or losses are then offset against related results on the hedged
transaction in the statements of operations.
A company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting. Only
derivative instruments that are expected to be highly effective in offsetting anticipated gains or losses on the hedged cash flows
and that are subsequently documented to have been highly effective can qualify for hedge accounting. Effectiveness must be
assessed both at inception of the hedge and on an ongoing basis. Any ineffectiveness in hedging instruments whereby gains or
losses do not exactly offset anticipated gains or losses of hedged cash flows is measured and recognized in earnings in the
period in which it occurs. When using hedge accounting, we assess hedge effectiveness quarterly based on total changes in the
111
Noble Energy, Inc.
Notes to Consolidated Financial Statements
derivative instrument’s fair value by performing regression analysis. A hedge is considered effective if certain statistical tests
are met. We record hedge ineffectiveness in (gain) loss on commodity derivative instruments.
Accounting for Commodity Derivative Instruments 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.
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
arrangement with netting clauses.
Accounting for Interest Rate Derivative Instruments We designate interest rate derivative instruments as cash flow hedges.
Changes in fair value of interest rate swaps or interest rate “locks” used as cash flow hedges are reported in AOCL, to the
extent the hedge is effective, until the forecasted transaction occurs, at which time they are recorded as adjustments to interest
expense over the term of the related notes.
See Note 10. Derivative Instruments and Hedging Activities.
Stock-Based Compensation Stock options and other stock-based compensation 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. See Note 14. 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 our defined benefit pension, restoration and other postretirement benefit
plans in the consolidated balance sheets, with a corresponding adjustment to AOCL, net of tax. The amount remaining in
AOCL at December 31, 2012 represents unrecognized net actuarial loss, unrecognized prior service cost, and unrecognized net
transition obligation remaining from the initial adoption of US GAAP for employers' accounting for pensions and other
postretirement benefits. These amounts are currently being recognized as net periodic benefit cost pursuant to our historical
accounting 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. See Note
14. Stock-Based and Other Compensation Plans.
Income Taxes 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. See
Note 13. 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.
When we have an interest with other producers in properties from which natural gas is produced, we use the entitlements
method to account for any imbalances. Imbalances occur when we sell more or less product than we are entitled to under our
ownership percentage. Revenue is recognized only on the entitlement percentage of volumes sold. Any amount that we sell in
excess of our entitlement is treated as a liability and is not recognized as revenue. Any amount of entitlement in excess of the
amount we sell is recognized as revenue and a receivable is accrued.
Basic and Diluted Earnings Per Share Basic earnings 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. See Note 16. Earnings Per Share.
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 20. Commitments and Contingencies.
112
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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 17. Segment Information.
Changes in Shareholders’ Equity On April 24, 2012, our shareholders voted to approve an amendment to the Company’s
Certificate of Incorporation to (i) increase the number of authorized shares of our common stock from 250 million to 500
million shares and (ii) reduce the par value of the Company’s common stock from $3.33 1/3 per share to $0.01 per share. See
the Consolidated Statements of Shareholders' Equity.
Recently Issued Accounting Standards In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting
Standards Update No. 2011-04: Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value
Measurement and Disclosure Requirements in US GAAP and IFRSs (ASU 2011-04). ASU 2011-04 clarifies application of fair
value measurement and disclosure requirements and is effective for annual and interim periods beginning after December 15,
2011. As of March 31, 2012, we have adopted the provisions of ASU 2011-04, which did not impact our consolidated financial
statements. The only impact was to our fair value disclosures. See Note 15. Fair Value Measurements and Disclosures.
In December 2011, the FASB issued Accounting Standards Update No. 2011-11 Balance Sheet (Topic 210): Disclosures about
Offsetting Assets and Liabilities (ASU 2011-11). ASU 2011-11 requires that an entity disclose information about offsetting and
related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial
position. ASU 2011-11 is effective for annual periods beginning on or after January 1, 2013. We are currently evaluating the
provisions of ASU 2011-11 and assessing the impact, if any, it may have on our financial position and results of operations.
113
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 2. Additional Financial Statement Information
Additional statements of operations information is as follows:
(millions)
Other Revenues (1)
Production Expense
Lease Operating Expense
Production and Ad Valorem Taxes
Transportation Expense
Total
Other Operating Expense, Net
Deepwater Gulf of Mexico Moratorium Expense (2)
Electricity Generation Expense (1)
Other, Net
Total
Other Non-Operating (Income) Expense, Net
Deferred Compensation Expense (3)
Interest Income (4)
Other (Income) Expense, Net
Total
Year Ended December 31,
2012
2011
2010
—
431
151
91
673
$
$
— $
—
25
25
$
6
(1)
1
6
$
$
32
346
146
66
558
18
26
42
86
8
(8)
9
9
$
$
$
$
$
$
72
329
125
61
515
27
39
(2)
64
15
(7)
(2)
6
$
$
$
$
$
$
(1) Other revenues consist primarily of electricity sales from the Machala power plant, located in Machala, Ecuador, through May 2011.
Electricity generation expense includes all operating and non-operating expenses associated with the plant, including depreciation and
changes in the allowance for doubtful accounts. In May 2011, we transferred our assets in Ecuador to the Ecuadorian government.
(2) Amounts relate to rig stand-by expense incurred due to the deepwater Gulf of Mexico drilling moratorium.
(3) Amounts represent increases in the fair value of shares of our common stock held in a rabbi trust.
(4)
Interest income for 2010 includes $3 million related to the refund of deepwater Gulf of Mexico royalties.
114
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Additional balance sheet information is as follows:
(millions)
Accounts Receivable, Net
Commodity Sales
Joint Interest Billings
Other
Allowance for Doubtful Accounts
Total
Other Current Assets
Inventories, Current
Commodity Derivative Assets, Current
Deferred Income Taxes, Net, Current (1)
Probable Insurance Claims (2)
Assets Held for Sale (3)
Prepaid Expenses and Other Assets, Current
Total
Other Noncurrent Assets
Equity Method Investments
Mutual Fund Investments
Commodity Derivative Assets, Noncurrent
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
CONSOL Installment Payment, Net (4)
Current Portion of FPSO Lease Obligation
Liabilities Associated with Assets Held for Sale (3)
Other Liabilities, Current
Total
Other Noncurrent Liabilities
Deferred Compensation Liabilities, Noncurrent
Asset Retirement Obligations, Noncurrent
Accrued Benefit Costs, Noncurrent (5)
Commodity Derivative Liabilities, Noncurrent
Other Liabilities, Noncurrent
Total
December 31,
2012
2011
$
$
$
$
$
$
$
$
$
$
349
486
139
(10)
964
90
63
106
45
45
71
420
367
103
21
106
597
113
7
203
69
55
324
48
12
193
1,024
229
333
116
3
129
810
$
$
$
$
$
$
$
$
$
$
356
313
123
(9)
783
78
10
41
15
—
36
180
329
99
37
83
548
121
76
127
33
56
324
45
—
143
925
222
344
88
7
91
752
(1)
Increase from December 31, 2011 is due to reclassification of deferred income tax assets from long-term to short-term as certain
foreign entities are estimated to begin utilizing net operating loss carryforwards in 2013.
(2) Amounts represent the costs incurred to date of the Leviathan-2 appraisal well and expected well abandonment costs in excess of the
insurance deductible less insurance proceeds received to date. See Note 11. Asset Retirement Obligations.
(3) Assets held for sale consist primarily of North Sea oil and gas properties, and liabilities associated with assets held for sale consists
primarily of asset retirement obligations. See Note 3. Acquisitions and Divestitures.
(4) See Note 3. Acquisitions and Divestitures and Note 12. Long-Term Debt.
115
Noble Energy, Inc.
Notes to Consolidated Financial Statements
(5) Amount includes liabilities accrued under our defined benefit pension plan, restoration plan, and other postretirement benefit plans.
See Note 14. Stock-Based and Other Compensation Plans.
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 CONSOL Installment Payments, Net of Discount (1)
Increase in FPSO Lease Obligation (1)
(1) See Note 3. Acquisitions and Divestitures and Note 12. Long-Term Debt.
Note 3. Acquisitions and Divestitures
Year Ended December 31,
2012
2011
2010
$
$
107
168
—
—
$
32
288
639
66
66
173
—
266
Sale of North Sea Properties On August 13, 2012, we closed the sale of our 30% non-operated working interest in the
Dumbarton and Lochranza fields, located in the UK sector of the North Sea. Proceeds from the transaction were $117 million
and included final closing adjustments from the effective date of January 1, 2012. The net book value of assets sold was $255
million. Asset retirement obligations associated with the sale were $55 million. We reversed a deferred tax liability and
recognized a corresponding income tax benefit of $99 million related to the sale.
We continue to market our remaining North Sea properties. As of December 31, 2012, all the properties remaining in our North
Sea geographical segment are included in assets held for sale in our consolidated balance sheet. Our consolidated statements of
operations have been reclassified for all periods presented to reflect the operations of our North Sea geographical segment as
discontinued.
Included in income before income taxes during 2012, below, is exploratory expense of $27 million related to our Selkirk field.
During the fourth quarter of 2012, the nearby Bligh well, a potential co-development candidate for Selkirk, was drilled. Bligh
encountered hydrocarbons but disappointingly tight non-commercial reservoirs. Therefore, we determined that Selkirk was
uneconomic for joint development.
Upon reclassification as held for sale, depreciation, depletion, and amortization (DD&A) ceased for the North Sea segment. Our
long-term debt is recorded at the consolidated level; therefore no interest expense has been allocated to discontinued operations.
Summarized results of discontinued operations are as follows:
(millions)
Oil and Gas Sales
Income Before Income Taxes
Income Tax Expense
Operating Income, Net of Tax
Gain on Sale, Net of Tax
Discontinued Operations, Net of Tax
Year Ended December 31,
2012
2011
2010
$
$
208
101
55
46
16
62
$
$
357
215
174
41
—
41
$
$
309
183
89
94
—
94
116
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Sale of Onshore US Properties During the third quarter of 2012, we closed the sales of certain crude oil and natural gas
properties in Kansas, western Oklahoma, western Texas, and the Texas Panhandle with an effective date of April 1, 2012.
Additionally, in June 2012, we closed the sale of non-core assets located in Wyoming. The information regarding the assets
sold is as follows:
(millions)
Cash Proceeds
Less
Net Book Value of Assets Sold
Goodwill Allocated to Assets Sold
Asset Retirement Obligations Associated with Assets Sold
Other Closing Adjustments
Gain on Divestitures
Year Ended
December 31,
2012
$
$
1,044
(836)
(61)
20
(13)
154
We continue to market certain non-core onshore US properties. However, none of these assets met the criteria for
reclassification as an asset held-for-sale at December 31, 2012.
Marcellus Shale Joint Venture On September 30, 2011, we closed an agreement with a subsidiary of CONSOL Energy Inc.
(CONSOL) for the development of Marcellus Shale properties in southwest Pennsylvania and northwest West Virginia. Under
the agreement, we acquired a 50% interest in approximately 628,000 net undeveloped acres, certain producing properties, and
existing infrastructure, such as pipeline and gathering facilities, for approximately $1.3 billion, including post-closing
adjustments. We and CONSOL also formed CONE Gathering LLC (CONE) to own and operate the existing and future
infrastructure. We have paid a total of $938 million as of December 31, 2012, and the remainder is due September 30, 2013.
See Note 12. Long-Term Debt.
As part of the joint venture transaction, we agreed to fund one-third of CONSOL’s 50% working interest share of future drilling
and completion costs, capped at $400 million each year, up to approximately $2.1 billion (CONSOL Carried Cost Obligation),
which is expected to be paid out over a multi-year period. The CONSOL Carried Cost Obligation is suspended if average Henry
Hub natural gas prices fall and remain below $4.00 per MMBtu in any three consecutive month period and will remain
suspended until average Henry Hub natural gas prices are above $4.00 per MMBtu for three consecutive months. The CONSOL
Carried Cost Obligation is currently suspended due to low natural gas prices.
As a result of the transaction, we recorded the following:
(millions)
Unproved Oil and Gas Properties
Proved Oil and Gas Properties
Investment in CONE Gathering LLC
Total Assets Acquired (1)
(1) Total reflects impact of $17 million imputed interest on CONSOL installment payments.
December 31,
2012
$
$
803
386
69
1,258
117
Noble Energy, Inc.
Notes to Consolidated Financial Statements
We used an income approach to estimate the fair value of the proved oil and gas properties as of the acquisition date. We
utilized a discounted cash flow model which took into account the following inputs to arrive at estimates of future net cash
flows:
estimated quantities of crude oil and natural gas reserves prepared by our qualified petroleum engineers;
•
• management’s estimates of future commodity prices based on NYMEX Henry Hub natural gas futures prices and
•
•
adjusted for estimated location and quality differentials;
estimated future production rates based on our experience with similar properties which we operate; and
estimated timing and amounts of future operating and development costs based on our experience with similar
properties which we operate.
We discounted the resulting future net cash flows using a market-based weighted average cost of capital rate determined
appropriate at the acquisition date. The fair value of the proved producing properties is considered a Level 3 fair value
measurement.
Exit from Ecuador On November 25, 2010, the government of Ecuador terminated the Block 3 PSC (100% working interest)
with our subsidiary, EDC Ecuador Ltd. as we had not negotiated a service contract on Block 3 in accordance with the terms of a
newly enacted hydrocarbon law. The hydrocarbon law aimed to change current production-sharing arrangements into service
contracts and provided for renegotiation of certain contracts.
In May 2011, we transferred our assets in Ecuador to the Ecuadorian government. We received cash proceeds of $73 million
for the transfer of our offshore Amistad field assets, onshore gas processing facilities and Block 3 PSC and the assignment of
the Machala Power electricity concession and its associated assets. Our net book value for the assets had been reduced due to
previous impairment charges, resulting in a pre-tax gain of $25 million. We did not consider the property disposition material
for discontinued operations presentation.
DJ Basin Asset Acquisition In March 2010, we acquired substantially all of the US Rocky Mountain assets of Petro-Canada
Resources (USA) Inc. and Suncor Energy (Natural Gas) America Inc. for $498 million. The acquisition included properties
located in the DJ Basin, one of our core operating areas. The total purchase price was allocated to the proved and unproved
properties acquired based on fair values at the acquisition date.
The total purchase price and allocation of the total purchase price are as follows:
(millions)
Total Purchase Price
Cash Paid
Net Liabilities Assumed
Total
Allocation of Total Purchase Price
Proved Oil and Gas Properties
Unproved Oil and Gas Properties
Total
December 31,
2010
$
$
$
$
458
40
498
352
146
498
Sale of Onshore US Assets In August 2010, we sold non-core assets in the Mid-Continent and Illinois Basin areas. Information
regarding the assets sold is as follows:
118
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Year Ended
December 31,
2010
(millions)
Cash Proceeds
Less
Net Book Value of Assets Sold
Goodwill Allocated to Assets Sold
Asset Retirement Obligations Associated with Assets Sold
Other Closing Adjustments
Gain on Asset Sale
Note 4. Asset Impairments
Pre-tax (non-cash) asset impairment charges were as follows:
(millions)
Piceance (Onshore US)
South Raton (Deepwater Gulf of Mexico)
Mari-B, Noa, Pinnacles (Offshore Israel)
East Texas (Onshore US)
Tri-State (Onshore US)
Iron Horse (Onshore US)
Other Onshore US Properties
New Albany Shale (Onshore US)
Noa/Noa South (Offshore Israel)
Raton (Deepwater Gulf of Mexico)
Main Pass (Gulf of Mexico Shelf)
Total
$
$
Year Ended December 31,
2011
2010
2012
$
39
34
31
—
—
—
—
—
—
—
—
$
487
$
—
—
128
121
15
6
—
—
—
—
552
(394)
(61)
10
3
110
—
—
—
—
—
89
—
19
25
6
5
$
104
$
757
$
144
2012 Asset Impairments Due to recent declines in realized natural gas prices associated with our Piceance development,
onshore US, and recent declines in near-term crude oil prices associated with our South Raton development in the deepwater
Gulf of Mexico, we determined that their carrying amounts were not recoverable from future cash flows and, therefore, were
impaired. In addition, due to end-of-field life declines in production of our Mari-B, Noa and Pinnacles fields, offshore Israel,
we determined that the carrying amount was not recoverable from future cash flows and, therefore, was impaired. The assets
were written down to their estimated fair values, which were determined using discounted cash flow models. The discounted
cash flow models included management’s estimates of future oil and 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.
2011 Asset Impairments Due to a significant decline in spot and five-year forward natural gas prices, specifically during the
fourth quarter of 2011, as well as field performance, we determined that the carrying amounts of certain of our onshore US
developments were not recoverable from future cash flows and, therefore, were impaired. The assets were written down to their
estimated fair values, which were determined using discounted cash flow models, as described above.
2010 Asset Impairments Due to declines in natural gas prices and recent drilling results, we determined that the carrying
amount of our onshore US development at Iron Horse was not recoverable from future cash flows and, therefore, was impaired.
We also recorded impairments of our non-core, New Albany Shale assets which had been reclassified to held-for-sale; our
deepwater Gulf of Mexico development at Raton, primarily due to declines in natural gas prices; a Gulf of Mexico shelf asset;
and our investment in the Noa/Noa South development, offshore Israel. At December 31, 2010, we believed that it was less
likely that Noa would be pursued for development due to near-term capability at the Mari-B field and the longer-term outlook
from our discoveries at Tamar and Leviathan. During 2011, due to unexpected natural gas supply disruptions into Israel, we
119
Noble Energy, Inc.
Notes to Consolidated Financial Statements
decided to develop Noa/Noa South. The Iron Horse, Raton and Gulf of Mexico shelf assets were written down to their
estimated fair values, which were determined using discounted cash flow models, as described above. The New Albany shale
assets were written down to anticipated sales proceeds less costs to sell.
See also Note 15. Fair Value Measurements and Disclosures.
Note 5. Allowance for Doubtful Accounts
Changes in the allowance for doubtful accounts were as follows:
(millions)
Balance, Beginning of Period
Changes
Changes in Ecuador Receivable, Net(1)
Other Changes
Net Changes
Balance, End of Period
Year Ended December 31,
2012
2011
2010
$
$
9
$
27
$
—
1
1
(19)
1
(18)
10
$
9
$
31
(6)
2
(4)
27
(1) During 2011, recovery of approximately $19 million for outstanding receivables was included in the final terms of our agreement to
transfer our assets and the associated electricity concession and PSC to the Ecuadorian government. See Note 3. Acquisitions and
Divestitures.
Note 6. Inventories
Inventories consisted of the following:
(millions)
Materials and Supplies
Crude Oil
Total
December 31,
2012
2011
$
$
68
22
90
$
$
56
22
78
120
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 7. 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.
Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed
in the same period:
Year Ended December 31,
2012
2011
2010
(millions)
Capitalized Exploratory Well Costs, Beginning of Period
Additions to Capitalized Exploratory Well Costs Pending Determination of
Proved Reserves
Reclassified to Proved Oil and Gas Properties Based on Determination of
Proved Reserves
Capitalized Exploratory Well Costs Charged to Expense (1)
Other (2)
Capitalized Exploratory Well Costs, End of Period
$
696
$
466
$
360
(18)
(114)
(24)
900
$
$
322
(55)
(37)
—
696
$
463
161
(155)
(3)
—
466
(1) Amount primarily represents Deep Blue (deepwater Gulf of Mexico) exploratory well costs capitalized prior to December 31, 2012.
Although hydrocarbons were found in both the initial exploration well and subsequent sidetrack, we and our partners decided not to
proceed with additional appraisal activities.
(2) Amount relates to Selkirk (North Sea) exploratory well costs capitalized prior to December 31, 2012. During the fourth quarter of 2012,
our Selkirk field, which is included in discontinued operations, was determined to be uneconomic for joint development and was charged
to exploration expense. See Note 3. Acquisitions and Divestitures.
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:
December 31,
2012
2011
2010
(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
$
$
355
$
318
$
$
545
900
14
$
378
696
13
166
300
466
13
121
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, 2012:
Total
2011
2010
2009 & Prior
Suspended Since
(millions)
Country/Project:
Offshore Equatorial Guinea
Carla
Carmen
Diega
Felicita
Yolanda
Offshore Cameroon
YoYo
Offshore Israel
Leviathan
Leviathan-1 Deep
Tanin 1
Dolphin 1
Dalit
Offshore Cyprus
Cyprus A-1
Deepwater Gulf of Mexico
Gunflint
Other
Projects of $10 million or less each
Total
$
$
12
22
82
35
18
45
108
28
31
22
22
57
54
12
1
45
2
1
5
67
28
31
22
—
57
—
$
— $
1
2
2
1
2
41
—
—
—
1
—
—
5
55
—
20
35
31
16
38
—
—
—
—
21
—
54
$
9
545
$
—
271
$
$
4
219
Carla/Carmen/Diega Carla is a 2011 crude oil discovery on both Block O and I, Carmen is a 2009 crude oil discovery on
Block O, and Diega is a 2008 condensate and oil discovery on Block I. We continue our appraisal program for Carla and Diega
and have encountered hydrocarbons in multiple appraisal wells and side-tracks. We are currently evaluating regional
development scenarios for these three discoveries, which includes possible sanctioning of Carla during 2013.
Felicita/Yolanda Felicita is a 2008 condensate and natural gas discovery on Block O. Yolanda is a 2008 condensate and natural
gas discovery on Block I. We are currently evaluating regional natural gas development options for these discoveries.
YoYo YoYo is a 2007 natural gas and condensate discovery. During 2011 we acquired and processed additional 3-D seismic
information and are continuing evaluations for future drilling potential. We are also working with the government of Cameroon
to assess gas commercialization options.
Leviathan Leviathan is a 2010 natural gas discovery. During 2012, we continued to evaluate the discovery with the successful
drilling of the Leviathan-3 appraisal well and spud the Leviathan-4 appraisal well. We have project and commercial teams in
place and are in the process of screening multiple development concepts. Due to Leviathan's size, full field development, and
realization of maximum economic value will require several development phases. Each of these development options would
require a multi-billion dollar investment and require a number of years to complete. Engineering design and planning work are
currently underway for a potential first phase of development. In addition, we announced that the partners in the Leviathan
Project had agreed in principle on a proposal to sell a 30% working interest in the Leviathan licenses to Woodside Energy Ltd.
(Woodside). Woodside is Australia’s largest producer of LNG with over 25 years of experience and has strong working
relationships with many potential customers in the Asian LNG markets.
122
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Leviathan-1 Deep In January 2012, we returned to the Leviathan-1 well and began drilling toward two deeper intervals in
order to evaluate them for the existence of crude oil (Leviathan-1 Deep). In May 2012, due to high well pressure and the
mechanical limits of the wellbore design, we suspended drilling operations. Although the well did not reach the planned
objective, we are encouraged by the possibility of an active thermogenic (crude oil generating) hydrocarbon system at greater
depths within the basin. We are continuing our evaluation of Leviathan-1 Deep and will integrate the data from the Leviathan-1
Deep well into our model to update our analysis and design a drilling plan specifically to test the deep oil concept. We have
secured a rig with the capabilities necessary to reach the target objective and plan to begin drilling an exploratory well in fourth
quarter of 2013.
Tanin 1 Tanin 1 is a 2011 natural gas discovery located in the Alon A block, offshore Israel. We and our partners are currently
reviewing alternatives for the development of reserves from this asset.
Dolphin 1 Dolphin 1 is a 2011 natural gas discovery located in the Hanna license, southwest of the Tamar gas field. We and
our partners are currently reviewing alternatives for the development of reserves from this asset.
Dalit Dalit is a 2009 natural gas discovery. We and our partners are working on a development plan which would include tie-in
to the Tamar platform and have submitted a development plan to the Israeli government.
Cyprus During the fourth quarter of 2011, we drilled a successful natural gas exploration well (A-1) in Block 12. We
submitted an appraisal plan to the Cyprus government during July 2012 and are reviewing locations for appraisal drilling
activities.
Gunflint Gunflint (Mississippi Canyon Block 948) is a 2008 crude oil discovery. In July 2012, we drilled a successful Gunflint
appraisal well. We plan to drill a second appraisal well targeting the south area of the reservoir during first quarter of 2013.
Front-end conceptual studies have been completed, and we are working toward sanctioning of a scalable development project in
2013. We are currently targeting 2017 for production start-up utilizing a standalone facility. If we choose to connect to an
existing third-party host, the project could have an accelerated completion schedule.
Note 8. Equity Method Investments
Investments accounted for under the equity method consist primarily of the following:
•
•
•
45% interest in Atlantic Methanol Production Company, LLC (AMPCO), which owns and operates a methanol plant
and related facilities in Equatorial Guinea;
28% interest in Alba Plant LLC (Alba Plant), which owns and operates a liquefied petroleum gas processing plant in
Equatorial Guinea; and
50% interest in CONE Gathering LLC (CONE), which owns and operates natural gas gathering facilities servicing our
joint venture properties in the Marcellus Shale.
Equity method investments are included in other noncurrent assets in the consolidated balance sheets, and our share of earnings
is reported as income from equity method investees in the consolidated statements of operations. 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. At December 31, 2012, our retained earnings included $111
million related to the undistributed earnings of equity method investees.
The carrying value of our AMPCO investment was $10 million higher than the underlying net assets of the investee at
December 31, 2012. The difference is related to capitalized interest which is being amortized into earnings over the remaining
useful life of the plant.
Equity method investments are as follows:
(millions)
Equity Method Investments
AMPCO
Alba Plant
CONE
Other
Total Equity Method Investments
123
December 31,
2012
2011
$
$
137
93
121
16
367
$
$
147
96
72
14
329
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
Note 9. Goodwill
Changes in the carrying amount of goodwill were as follows:
(millions)
Goodwill, Beginning Balance
Amount Allocated to Sale of Business (1)
Goodwill, Ending Balance
(1) See Note 3. Acquisitions and Divestitures.
December 31,
2012
2011
$
$
384
902
348
24
374
827
360
16
Year Ended December 31,
2012
2011
2010
$
$
1,173
361
812
(5)
817
200
617
$
$
$
$
1,139
335
804
(12)
816
201
615
$
$
809
296
513
(12)
525
133
392
December 31,
2012
2011
696
(61)
635
$
$
696
—
696
Note 10. Derivative Instruments and Hedging Activities.
Objective and Strategies for Using Derivative Instruments In order to mitigate the effect of commodity price volatility and
enhance the predictability of cash flows relating to the marketing of our crude oil and natural gas, we enter into crude oil and
natural gas price hedging arrangements with respect to a portion of our expected production. The derivative instruments we use
include variable to fixed price commodity swaps, two-way and three-way collars and basis swaps.
The fixed price swap, two-way collar, and basis swap 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.
124
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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.
We also may enter into forward contracts to hedge anticipated exposure to interest rate risk associated with public debt
financing.
While these instruments mitigate the cash flow risk of future reductions in commodity prices or increases in interest rates, they
may also curtail benefits from future increases in commodity prices or decreases in interest rates.
See Note 15. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair
values of our derivative instruments.
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 or higher interest rates, and could incur a loss.
Interest Rate Derivative Instrument In January 2010, we entered into an interest rate forward starting swap to effectively fix
the cash flows related to interest payments on our anticipated March 2011 debt issuance. During first quarter 2011, the net
liability position on the swap was reduced in our mark to market calculation, and we recognized a corresponding gain of $23
million, net of tax, in AOCL. On February 15, 2011 we settled the interest rate swap, which had a net liability position of $40
million at the time of settlement. Approximately $26 million, net of tax, was recorded in accumulated other comprehensive loss
(AOCL) and is being reclassified to interest expense over the term of the notes. The ineffective portion of the interest rate swap
was de minimis.
125
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Unsettled Derivative Instruments As of December 31, 2012, we had entered into the following crude oil derivative
instruments:
Settlement
Period
Type of Contract
Index
Bbls Per
Day
Instruments Entered Into as of December 31, 2012
Swaps
Weighted
Average
Fixed
Price
Weighted
Average
Short Put
Price
Collars
Weighted
Average
Floor
Price
Weighted
Average
Ceiling
Price
2013
2013
2013
2013
2013
2014
2014
2014
2014
Swaps
Swaps
Two-Way
Collars
Three-Way
Collars
Three-Way
Collars
Swaps
Swaps
Three-Way
Collars
Three-Way
Collars
NYMEX WTI
Dated Brent
NYMEX WTI
NYMEX WTI
Dated Brent
NYMEX WTI
Dated Brent
NYMEX WTI
Dated Brent
8,000 $
89.63
$
— $
3,000
98.03
5,000
7,000
26,000
11,000
10,000
4,000
11,000
—
—
—
90.26
105.14
—
—
— $
—
—
—
95.00
115.00
—
—
63.57
83.57
109.04
82.50
100.93
126.63
—
—
—
—
—
—
77.00
92.00
106.13
85.45
99.09
128.40
As of December 31, 2012, we had entered into the following natural gas derivative instruments:
Settlement
Period
Type of Contract
Index
MMBtu
Per Day
Instruments Entered Into as of December 31, 2012
Swaps
Weighted
Average
Fixed
Price
Weighted
Average
Short Put
Price
Collars
Weighted
Average
Floor
Price
Weighted
Average
Ceiling
Price
2013
2013
2013
2014
2014
Swaps
Two-Way Collars
Three-Way
Collars
NYMEX HH
NYMEX HH
60,000 $
40,000
NYMEX HH
100,000
Swaps
Three-Way
Collars
NYMEX HH
60,000
NYMEX HH
130,000
4.58
—
—
4.24
—
$
— $
—
3.88
—
2.56
— $
3.25
4.75
—
3.56
—
5.14
5.63
—
5.21
126
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
Asset Derivative Instruments
Liability Derivative Instruments
December 31,
2012
December 31,
2011
December 31,
2012
December 31,
2011
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
63
21
84
$
$
Current
Liabilities
Noncurrent
Liabilities
$
$
10
37
47
Current
Liabilities
7
Noncurrent
Liabilities
3
10
$
$
76
7
83
The effect of derivative instruments on our consolidated statements of operations was as follows:
(millions)
Realized Mark-to-Market (Gain) Loss
Unrealized Mark-to-Market (Gain) Loss
Total (Gain) Loss on Commodity Derivative Instruments
Year Ended December 31,
2012
2011
2010
$
$
$
34
(109)
(75) $
(64) $
22
(42) $
(87)
(70)
(157)
Derivative Instruments in Cash Flow Hedge Relationships
Amount of (Gain) Loss on
Derivative Instruments
Recognized in Other
Comprehensive (Income)
Loss
Amount of (Gain) Loss on
Derivative Instruments
Reclassified from
Accumulated Other
Comprehensive (Income) Loss
2012
2011
2010
2012
2011
2010
(millions)
Commodity Derivative Instruments in Previously
Designated Cash Flow Hedging Relationships (1)
Crude Oil
Natural Gas
Interest Rate Derivative Instruments in Cash Flow Hedging
Relationships
Total
$ — $ — $ — $ — $ — $
19
—
—
$ — $
—
(23)
(23) $
—
63
63
$
—
1
1
$
—
1
1
1
1
$
21
(1)
Includes effect of commodity derivative instruments previously accounted for as cash flow hedges. All net derivative gains and losses
that were deferred in AOCL as a result of previous cash flow hedge accounting, had been reclassified to earnings by December 31,
2010.
AOCL at December 31, 2012 included deferred losses of $25 million, net of tax, related to interest rate derivative instruments.
This amount will be reclassified to earnings as an adjustment to interest expense over the terms of our senior notes due April
2014 and March 2041. Approximately $2 million of deferred losses (net of tax) will be reclassified to earnings during the next
12 months and will be recorded as an increase in interest expense.
127
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 11. Asset Retirement Obligations
Asset retirement obligations (ARO) consist primarily of estimated costs of dismantlement, removal, site reclamation and similar
activities associated with our oil and gas properties. Changes in asset retirement obligations were as follows
(millions)
Asset Retirement Obligations, Beginning Balance
Liabilities Incurred
Liabilities Settled
Revision of Estimate
Accretion Expense
Other
Asset Retirement Obligations, Ending Balance
Year Ended December 31,
2012
2011
$
$
377
43
(112)
102
22
(30)
402
$
$
253
23
(24)
105
20
—
377
For the year ended December 31, 2012, liabilities incurred include $6 million for onshore US development, $8 million for
deepwater Gulf of Mexico, and $30 million for offshore Israel. Liabilities settled in 2012 include $20 million related to non-
core onshore US assets sold, $55 million related to North Sea assets sold, and $34 million related to the Leviathan-2 appraisal
well, offshore Israel. Revisions relate primarily to changes in estimated costs for future abandonment activities and include $54
million for onshore US, $6 million for deepwater Gulf of Mexico, $26 million for offshore Israel, and $16 million for offshore
China. Other includes North Sea ARO liabilities transferred to liabilities associated with assets held for sale. See Note 2.
Additional Financial Statement Information and Note 3. Acquisitions and Divestitures.
For the year ended December 31, 2011, liabilities incurred were primarily due to the Marcellus Shale asset acquisition as well
as additions for the Alen project in Equatorial Guinea and Lochranza project in the North Sea. Liabilities settled in 2011 related
primarily to deepwater Gulf of Mexico and Gulf of Mexico shelf properties. Revisions in 2011 resulted from changes in
estimated abandonment costs mainly in the DJ Basin and deepwater Gulf of Mexico.
Accretion expense is included in DD&A expense in the consolidated statements of operations.
128
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 12. Long-Term Debt
Our debt consists of the following:
December 31,
2012
December 31,
2011
Debt
Interest Rate
Debt
Interest Rate
$
(millions, except percentages)
Credit Facility, due October 14, 2016 (1)
CONSOL Installment Payments
FPSO Lease Obligation
5¼% Senior Notes, due April 15, 2014
8¼% Senior Notes, due March 1, 2019
4.15% Senior Notes, due December 15, 2021
7¼% Senior Notes, due October 15, 2023
8% Senior Notes, due April 1, 2027
6% Senior Notes, due March 1, 2041
7¼% Senior Debentures, due August 1, 2097
Total
Unamortized Discount
Total Debt, Net of Discount
Less Amounts Due Within One Year
Current portion of CONSOL Installment
Payment, net of discount
FPSO Lease Obligation
Long-Term Debt Due After One Year
$
—
328
311
200
1,000
1,000
100
250
850
84
4,123
(15)
4,108
(324)
(48)
3,736
$
—
1.79% (2)
—
5.25%
8.25%
4.15%
7.25%
8.00%
6.00%
7.25%
$
—
656
355
200
1,000
1,000
100
250
850
84
4,495
(26)
4,469
(324)
(45)
4,100
—
1.76% (2)
—
5.25%
8.25%
4.15%
7.25%
8.00%
6.00%
7.25%
(1) Our Credit Agreement provides for a $4.0 billion unsecured revolving Credit Facility. The Credit Facility is available for general corporate
(2)
purposes.
Imputed rate based on the prevailing market rates for similar debt instruments at the date of assessment.
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. Debt issuance costs of approximately $35 million remain and are being
amortized to expense over the life of the related debt issues and are included in current and long-term assets based on their
related debt terms.
Credit Facility On September 28, 2012, we exercised our option to increase our bank revolving credit facility (the Credit
Facility) to $4.0 billion. The credit facility was previously committed in the amount of $3.0 billion as of December 31, 2011.
Debt issuance costs of approximately $4 million were incurred and are being amortized to expense over the remaining term of
the Credit Facility which will mature on October 14, 2016.
The Credit Facility (i) provides for facility fee rates that range from 12.5 basis points to 30 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 100 basis points to 145 basis points depending upon our credit rating.
The Credit Agreement requires that our total debt to capitalization ratio (as defined in the Credit Agreement), 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 Credit Facility and require the immediate
repayment of any outstanding advances under the Credit Facility. As of December 31, 2012, we were in compliance with our
debt covenants.
129
Noble Energy, Inc.
Notes to Consolidated Financial Statements
The Credit Facility is available for general corporate purposes. Certain lenders that are a party to the Credit Agreement 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.
2011 Debt Offerings On February 18, 2011, we closed an offering of $850 million senior unsecured notes receiving net
proceeds of $836 million, after deducting discount and underwriting fees. The notes are due March 1, 2041, and pay interest
semi-annually at 6%. Total debt issuance costs of approximately $9 million were incurred and are being amortized to expense
over the term of the notes. Approximately $470 million of the net proceeds were used to repay outstanding indebtedness under
our revolving credit facility and the balance of the proceeds has been used for general corporate purposes.
On December 8, 2011, we closed an offering of $1.0 billion senior unsecured notes receiving net proceeds of $992 million, after
deducting discount and underwriting fees. The notes are due December 15, 2021, and pay interest semi-annually at 4.15%. Total
debt issuance costs of approximately $8 million were incurred and are being amortized to expense over the term of the notes.
Approximately $400 million of the net proceeds were used to repay outstanding indebtedness under our revolving credit facility
and the balance of the proceeds has been used for general corporate purposes.
CONSOL Installment Payments On September 30, 2011, we closed an agreement with CONSOL for the development of
Marcellus Shale properties. In addition to the cash paid at closing, we agreed to make two installment payments of $328 million
each, the first of which was paid on September 30, 2012. The second installment payment, which has been discounted at the
prevailing market rates for similar debt instruments, is due on September 30, 2013 and has been reclassified to current liabilities
as of December 31, 2012. See Note 3. Acquisitions and Divestitures and Note 15. Fair Value Measurements and Disclosures.
Aseng FPSO Lease Obligation We lease an FPSO used in the Aseng field, offshore Equatorial Guinea. The amount of the
Aseng FPSO lease obligation is based on the discounted present value of future minimum lease payments, and therefore does
not reflect future minimum lease payments. Amounts due within one year equal the amount by which the Aseng FPSO lease
obligation is expected to be reduced during the next 12 months. See Note 20. Commitments and Contingencies for future
Aseng FPSO lease payments.
Annual Debt Maturities Annual maturities of outstanding debt, excluding Aseng FPSO lease payments, are as follows:
(millions)
December 31, 2012
2013
2014
2015
2016
2017
Thereafter
Total
Note 13. Income Taxes
Debt
Principal
Payments
$
$
328
200
—
—
—
3,284
3,812
Components of income (loss) from continuing operations before income taxes are as follows:
(millions)
Domestic
Foreign
Total
Year Ended December 31,
2012
2011
2010
$
$
92
1,264
1,356
$
$
(537) $
1,039
502
$
234
614
848
130
Noble Energy, Inc.
Notes to Consolidated Financial Statements
The income tax provision (benefit) from continuing operations consists of the following:
(millions)
Current Taxes
Federal
State
Foreign
Total Current
Deferred Taxes
Federal
State
Foreign
Total Deferred
Total Income Tax Provision
Effective Tax Rate
A reconciliation of the federal statutory tax rate to the effective tax rate is as follows:
(percentages)
Federal Statutory Rate
Effect of
Earnings of Equity Method Investees
State Taxes, Net of Federal Benefit
Difference Between US and Foreign Rates
Foreign Exploration Loss
Change in Valuation Allowance
Oil Profits Tax - Israel
Tax Contingency
Other, Net
Effective Rate
Year Ended December 31,
2012
2011
2010
$
$
$
$
14
1
143
158
60
1
172
233
391
28.8%
$
$
11
2
155
168
(130)
(3)
55
(78)
90
17.9%
25
2
97
124
86
1
6
93
217
25.6%
Year Ended December 31,
2012
2011
2010
35.0
(4.9)
0.2
(4.9)
(3.8)
4.3
0.9
1.8
0.2
28.8
35.0
(13.3)
(0.1)
(7.0)
(4.2)
6.6
2.6
—
(1.7)
17.9
35.0
(4.8)
0.4
(1.2)
—
(2.7)
(1.9)
—
0.8
25.6
131
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Deferred tax assets and liabilities resulted from the following:
(millions)
Deferred Tax Assets
Loss Carryforwards
Employee Compensation & Benefits
Foreign Tax Credits
Other
Total Deferred Tax Assets
Valuation Allowance - Foreign Loss Carryforwards
Valuation Allowance - Foreign Tax Credits
Net Deferred Tax Assets
Deferred Tax Liabilities
Property, Plant and Equipment, Principally Due to Differences in Depreciation, Amortization,
Lease Impairment and Abandonments
Total Deferred Tax Liability
Net Deferred Tax Liability
Net deferred tax liabilities were classified in the consolidated balance sheets as follows:
(millions)
Deferred Income Tax Asset - Current
Deferred Income Tax Liability - Current
Deferred Income Tax Liability - Noncurrent
Net Deferred Tax Liability
December 31,
2012
2011
$
$
$
$
$
235
134
38
81
488
(81)
(38)
369
200
164
57
86
507
(65)
(57)
385
(2,481)
(2,481)
(2,112) $
(2,409)
(2,409)
(2,024)
December 31,
2012
2011
$
106
—
(2,218)
(2,112) $
41
(6)
(2,059)
(2,024)
Deferred Tax Assets 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, projected future taxable income
and tax planning strategies in making this assessment. Based upon the level of historical taxable income and projections for
future taxable income over the periods in which the deferred tax assets are deductible, we believe it is more likely than not that
we will realize the benefits of these deductible differences at December 31, 2012. 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.
The valuation allowance on the deferred tax assets associated with foreign loss carryforwards totaled $81 million in 2012, $65
million in 2011, and $70 million in 2010. The changes to the valuation allowance for the loss carryforwards between periods
was attributable to changes in losses on projects in new venture activities which are not yet commercial.
During 2012, as a result of execution of tax planning strategies, we reversed a $57 million deferred tax asset for future foreign
tax credits from our foreign branch operations along with the corresponding valuation allowance. Additionally, we recorded a
$38 million valuation allowance on excess foreign tax credits and released $12 million of deferred tax liability for a net
increase in deferred income tax expense.
During 2011, we recorded a $57 million increase in the valuation allowance against our deferred tax asset for foreign tax
credits. This deferred tax asset was fully offset by a valuation allowance because, based on our forecast of foreign tax credits,
we did not believe it was more likely than not that the asset would be realized.
During 2010, we reversed a $28 million valuation allowance that had been established against a deferred tax asset of the same
amount for the future foreign tax credits associated with deferred tax liabilities recorded by foreign branch operations and
recorded a corresponding reduction in income tax expense.
132
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Effective Tax Rate Our effective tax rate increased in 2012 as compared with 2011, primarily due to reduced impact of equity
method earnings, which had the effect of decreasing the 2011 rate. The rate also increased due to additional valuation
allowances and nondeductible allocation of goodwill to assets sold in 2012.
Our effective tax rate decreased in 2011 as compared with 2010. This decrease was due to the impact of higher equity method
earnings in 2011 which had the effect of decreasing the 2011 rate. The decrease was partially offset by the change in the Israeli
tax law discussed below. Additionally, in 2010, we reversed a $28 million valuation allowance, as discussed above, which
reduced income tax expense. Finally, the rate for 2010 was increased by a nondeductible allocation of goodwill to assets sold.
Changes in Israeli Tax Law In March 2011, the Israeli government enacted the Petroleum Profits Taxation Law, 2011, which
imposes additional income tax on oil and gas production. The Israeli government also repealed the percentage depletion
deduction and made certain changes to the rules for deducting tangible and intangible development costs. These changes
increased our 2011 consolidated effective income tax rate by approximately 4%. There was no remeasurement of our deferred
tax assets or liabilities as of December 31, 2010.
Accumulated Undistributed Earnings of Foreign Subsidiaries As of December 31, 2012, the accumulated undistributed
earnings of the foreign subsidiaries that have been permanently reinvested were approximately $2.6 billion. No US taxes have
been recorded on these earnings. Upon distribution of additional earnings in the form of dividends or otherwise, we would
likely be subject to US income taxes and foreign withholding taxes. It is not practicable, however, to determine precisely the
amount of taxes that may be payable on the eventual remittance of these earnings because of the possible application of US
foreign tax credits. Although we are currently claiming foreign tax credits, we may not be in a credit position when any future
remittance of foreign earnings takes place, or the limitations imposed by the Internal Revenue Code and IRS Regulations may
not allow the credits to be utilized during the applicable carryback and carryforward periods. However, if full use of tax credits
is assumed, we estimate that the future US taxes on eventual remittance would be approximately $685 million.
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 routinely made in the financial statements for differences between positions taken in tax returns
and amounts recognized in the financial statements in anticipation of the results of these audits.
In our major tax jurisdictions, the earliest years remaining open to examination are: U.S. - 2009, Equatorial Guinea - 2007,
Israel - 2008, and China - 2006.
Our policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense. However, we
did not accrue penalties at December 31, 2012 or 2011, because we believe that we are below the minimum statutory threshold
for imposition of penalties.
A reconciliation of our beginning and ending amounts of unrecognized tax benefits follows:
(millions)
Unrecognized Tax Benefits, Beginning Balance
Additions for tax positions related to current year
Additions for tax positions of prior years
Reductions for tax positions of prior years
Settlements
Unrecognized Tax Benefits, Ending Balance
Year Ended
December 31,
2012
$
$
—
(1)
24
—
—
23
As of December 31, 2012, approximately $23 million of unrecognized tax benefits would impact our effective tax rate if
recognized. The changes to our unrecognized tax benefits during the twelve months ended December 31, 2012 primarily
resulted from changes in various foreign tax return filings and positions. The adjustments to our reserves for uncertain tax
positions had a de minimis impact on our net income.
During the year ended December 31, 2012, we recognized and accrued a de minimis amount of interest and none in penalties.
We expect that our unrecognized tax benefits could continue to change due to the settlement of audits and the expiration of
statutes of limitation in the next twelve months; however, we do not anticipate any such change to have a significant impact on
our results of operations, financial position or cash flows in the next twelve months.
133
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 14. 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,
2012
2011
2010
$
$
$
$
48
17
65
$
(23) $
$
42
16
58
$
(20) $
39
15
54
(19)
Stock Option and Restricted Stock Plans Our stock option and restricted stock plans are described below.
1992 Stock Option and Restricted Stock Plan Under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan, as
amended (the 1992 Plan), the Compensation, Benefits and Stock Option Committee of the Board of Directors (the Committee)
may grant stock options and award restricted stock to our officers or other employees and those of our subsidiaries. On April
26, 2011, our stockholders approved the amendment and restatement of the 1992 Plan to increase the number of shares of our
common stock authorized for issuance under the plan from 24 million to 31 million shares and to modify certain plan
provisions. At December 31, 2012, 12,180,343 shares of our common stock were reserved for issuance, including 7,009,795
shares available for future grants and awards, under the 1992 Plan.
Stock options are issued with an exercise price equal to the market price 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 ten years from the grant date. Option grants generally vest ratably over a three-year period.
Restricted stock awards made under the 1992 Plan are subject to such restrictions, terms and conditions, including forfeitures, if
any, as may be determined by the Committee. During the Restricted Period, unless specifically provided otherwise in
accordance with the terms of the 1992 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. Restricted stock awards generally vest over three years. Shares of
restricted stock time-vest 20% after year one, an additional 30% after year two and the remaining 50% after year three.
2005 Stock Plan for Non-Employee Directors The 2005 Stock Plan for Non-Employee Directors of Noble Energy, Inc. (the
2005 Plan) provides for grants of stock options and awards of restricted stock to our non-employee directors. The 2005 Plan
superseded and replaced the 1988 Nonqualified Stock Option Plan for Non-Employee Directors. The total number of shares of
our common stock that may be issued under the 2005 Plan is 800,000. At December 31, 2012, 696,178 shares of our common
stock were reserved for issuance, including 476,873 shares available for future grants and awards under the 2005 Plan.
The 2005 Plan provides for the granting to a non-employee director of up to a maximum of 11,200 stock options on the date of
election to the Board of Directors, annual grants of 2,800 options per non-employee director on February 1 of each year, and
discretionary grants by the Board of Directors (with the February 1 annual and the discretionary grants made to a non-employee
director during any calendar year being limited to a combined maximum of 11,200 options). Options are issued with an
exercise price equal to the market price of our common stock on the date of grant and may be exercised one year after the date
of grant. The options expire ten years from the date of grant.
The 2005 Plan also provides for the awarding to a non-employee director of up to a maximum of 4,800 shares of restricted
stock on the date of election to the Board of Directors, annual awards of 1,200 shares of restricted stock per non-employee
director on February 1 of each year, and discretionary awards by the Board of Directors (with the February 1 annual and the
discretionary awards made to a non-employee director during any calendar year being limited to a combined maximum of
4,800 shares of restricted stock). Restricted stock is restricted for a period of at least one year from the date of award.
1988 Nonqualified Stock Option Plan for Non-Employee Directors The 1988 Nonqualified Stock Option Plan for Non-
Employee Directors of Noble Energy, Inc., as amended, (the 1988 Plan) provided for the issuance of stock options to our non-
employee directors. Options issued under the 1988 Plan may be exercised one year after grant and expire ten years from the
grant date. The 1988 Plan provided for the granting of a fixed number of stock options to each non-employee director annually
(10,000 stock options for the first calendar year of service and 5,000 stock options for each year thereafter) on February 1 of
each year. The 1988 Plan was terminated in 2005, and no additional options can be granted thereunder.
134
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Stock Option Grants The fair value of each stock option granted was 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 years 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, 2011
Granted
Exercised
Forfeited
Outstanding at December 31, 2012
Exercisable at December 31, 2012
Year Ended December 31,
2012
2011
2010
5.7
37.0%
0.9%
1.2%
5.7
36.2%
2.2%
1.1%
5.6
35.4%
2.6%
1.1%
$
31.98
$
30.17
$
25.05
Weighted
Average
Remaining
Contractual
Term
(in years)
Aggregate
Intrinsic
Value
(in millions)
Weighted
Average
Exercise
Price
(per share)
59.47
$
101.50
43.84
93.95
70.27
58.34
6.2
5.1
$
$
196
181
Options
6,365,816
1,225,827
(1,265,231)
(120,626)
6,205,786
4,164,438
$
$
The total intrinsic value of options exercised was $72 million in 2012, $40 million in 2011, and $68 million in 2010.
As of December 31, 2012, $36 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 1.4 years. We issue new shares of
our common stock to settle option exercises. Dividends are not paid on unexercised options.
135
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Restricted Stock Awards Restricted stock activity was as follows:
Outstanding at December 31, 2011
Awarded
Vested
Forfeited
Outstanding at December 31, 2012
Shares
Subject
to Service
Conditions
979,257
481,858
(472,691)
(55,193)
933,231
Weighted
Average
Award Date
Fair Value
(per share)
74.87
$
101.50
64.63
92.03
92.79
$
The total fair value of restricted stock that vested was $47 million in 2012, $57 million in 2011, and $43 million in 2010.
The weighted average award-date fair value of restricted stock awarded was $101.50 per share in 2012, $90.32 per share in
2011, and $75.07 per share in 2010.
Awards of time-vested restricted stock (shares subject to service conditions) were valued at the price of our common stock at the
date of award.
As of December 31, 2012, $45 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.
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 $17 million in 2012,
$14 million in 2011, and $11 million in 2010.
Deferred Compensation Plans 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 may elect to receive distributions in either cash or shares of our common stock. Components of the
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,
2012
2011
$
$
84
76
160
160
746,672
$
$
82
80
162
162
848,940
Assets of the 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 15. 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.
136
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Shares of our common stock held by the rabbi trust are accounted for as treasury stock (recorded at cost, $33.44 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 700,000 shares, or 94%, of our common stock held in the plan at December 31, 2012 were attributable to a
member of our Board of Directors. The shares are being distributed in equal installments over the next seven years.
Distributions of 100,000 shares were made in each of 2012 and 2011. In addition, plan participants sold 2,268 shares of our
common stock in 2012, 100 shares in 2011, and 100 shares in 2010. Proceeds were invested in mutual funds and/or distributed
to plan participants. Distributions to plan participants were valued at $19 million in 2012, $17 million in 2011 and $17 million
in 2010.
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 of $6 million in 2012,
$8 million in 2011 and $15 million in 2010.
We also maintain an unfunded deferred compensation plan for the benefit of certain of our employees. Deferred compensation
liabilities of $70 million, $60 million and $51 million were outstanding at December 31, 2012, 2011 and 2010, respectively,
under the unfunded plan.
Pension and Other Postretirement Benefit Plans We have a noncontributory, tax-qualified defined benefit pension plan
covering employees who were hired prior to May 1, 2006, and an unfunded, nonqualified restoration plan that provides the
pension plan formula benefits that cannot be provided by the qualified pension plan because of pay deferrals and the
compensation and benefit limitations imposed on the pension plan by the Internal Revenue Code of 1986, as amended. We
sponsor other plans, which include medical and life insurance benefits, for the benefit of our employees and retirees.
At December 31, 2012, the benefit obligations for these plans totaled $370 million and the fair value of plan assets totaled $247
million, resulting in a net liability of $123 million recognized in our consolidated balance sheet, of which $116 million was a
long-term liability. At December 31, 2011, the benefit obligations for these plans totaled $311 million and the fair value of plan
assets totaled $219 million, resulting in a net liability of $92 million recognized in our consolidated balance sheet, of which $88
million was a long-term liability. See Note 2. Additional Financial Statement Information. Pension plan assets include
diversified and high-quality federal money market funds, mutual funds and common collective trust funds. Net periodic benefit
cost related to these plans totaled $27 million in 2012, $21 million in 2011, and $21 million in 2010. We plan to make
contributions of $26 million in 2013.
Note 15. 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, which primarily include assets held in a rabbi trust, 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 consist of variable to fixed price commodity swaps,
two-way and three-way collars, and basis swaps. We estimate the fair values of these instruments based on 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 (for three-way
collars) and the contract floors and ceilings (for two-way and three-way collars) using an option pricing model which takes into
account market volatility, market prices and contract terms. See Note 10. 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.
137
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:
Fair Value Measurements Using
Quoted Prices
in
Active
Markets
(Level 1) (1)
Significant
Other
Observable
Inputs
(Level 2) (1)
Significant
Unobservable
Inputs (Level 3) (1) Adjustment (2)
Fair Value
Measurement
(millions)
December 31, 2012
Financial Assets
Mutual Fund Investments
$
103
$
— $
— $
— $
Commodity Derivative
Instruments
Financial Liabilities
Commodity Derivative
Instruments
Portion of Deferred Compensation
Liability Measured at Fair Value
December 31, 2011
Financial Assets
—
—
(160)
113
(39)
—
—
—
—
(29)
29
—
Mutual Fund Investments
$
99
$
— $
— $
— $
Commodity Derivative
Instruments
Financial Liabilities
Commodity Derivative
Instruments
Portion of Deferred Compensation
Liability Measured at Fair Value
—
—
(162)
99
(135)
—
—
—
—
(52)
52
—
103
84
(10)
(160)
99
47
(83)
(162)
(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.
138
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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 We determined that the carrying amounts of certain assets were not recoverable from future cash flows and,
therefore, were impaired. The assets were reduced to their estimated fair values. Information about the impaired assets is as
follows:
Fair Value Measurements Using
Significant
Other
Observable
Inputs
(Level 2) (1)
Significant
Unobservable
Inputs
(Level 3) (1)
Quoted Prices
in Active
Markets
(Level 1) (1)
Total Pre-tax
(Non-cash)
Impairment
Loss
Net Book
Value (2)
$
— $
— $
228
$
332
$
—
—
—
—
213
30
970
174
104
757
144
Description
(millions)
Year Ended December 31, 2012
Impaired Oil and Gas Properties
Year Ended December 31, 2011
Impaired Oil and Gas Properties
Year Ended December 31, 2010
Impaired Oil and Gas Properties
(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 the properties 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 oil and gas
production, commodity prices based on sales contract terms or NYMEX commodity price curves as of the date of the estimate,
estimated operating and development costs, and a risk-adjusted discount rate of 10%. See Note 4. 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. The
carrying amounts of the CONSOL installment payments approximate fair value because they have been discounted at the
prevailing market rates for similar debt instruments. As such, we consider the fair value of our CONSOL installment payments
to be Level 2 measurements on the fair value hierarchy. See Note 12. Long-Term Debt. Fair value information regarding our
debt is as follows:
(millions)
Long-Term Debt, Net of Unamortized Discount (1)
December 31,
2012
December 31,
2011
Carrying
Amount
Fair Value
Carrying
Amount
Fair Value
$
3,797
$
4,570
$
4,114
$
4,733
(1) Excludes Aseng FPSO lease obligation. No floating rate debt was outstanding at December 31, 2012 or December 31, 2011. See Note
12. Long-Term Debt.
139
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 16. Earnings Per Share
Basic earnings per share of common stock is computed using the weighted average number of shares of common stock
outstanding during each period. The diluted earnings per share of common stock include the effect of outstanding stock options,
shares of restricted stock, or shares of our common stock held in a rabbi trust (when dilutive). The following table summarizes
the calculation of basic and diluted earnings per share:
Year Ended December 31,
2012
2011
2010
(millions, except per share amounts)
Income from Continuing Operations Used for Diluted Earnings Per Share
Calculation
$
965
$
412
$
631
Weighted Average Number of Shares Outstanding, Basic
Incremental Shares From Assumed Conversion of Dilutive Stock Options
and Restricted Stock
Weighted Average Number of Shares Outstanding, Diluted
Earnings from Continuing Operations Per Share, Basic
Earnings from Continuing Operations Per Share, Diluted
178
2
180
5.43
5.37
$
176
3
179
2.34
2.31
$
175
2
177
3.61
3.56
$
Additional Information
Number of antidilutive stock options, shares of restricted stock and shares
of common stock in rabbi trust excluded from calculation above
Weighted average option exercise price per share
3
3
2
$
97.46
$
85.40
$
74.01
Note 17. Segment Information
We have operations throughout the world and manage our operations by country. The following information is grouped into
four components that are all primarily in the business of crude oil and natural gas exploration, development, and acquisition: the
United States; West Africa (Equatorial Guinea, Cameroon, Sierra Leone, and Senegal/Guinea-Bissau); Eastern Mediterranean
(Israel and Cyprus); and Other International and Corporate. Other International includes China, Ecuador (through May 2011),
Falkland Islands, Nicaragua and new ventures. As of December 31, 2012, our remaining North Sea assets were reclassified to
assets held for sale, and prior year amounts have been reclassified to exclude the North Sea geographical segment. See Note 3.
Acquisitions and Divestitures.
140
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Consolidated
United
States
West
Africa
Eastern
Mediterranean
Other Int'l &
Corporate
$
$
$
(millions)
Year Ended December 31, 2012
Revenues from Third Parties (1)
Income from Equity Method Investees
Total Revenues
DD&A
Asset Impairments
Gain on Divestitures
Gain on Commodity Derivative Instruments
Income (Loss) from Continuing Operations Before
Income Taxes
Equity Method Investments
Additions to Long-Lived Assets
Goodwill at End of Year
Total Assets at End of Year (2)
Year Ended December 31, 2011
Revenues from Third Parties (1)
Income from Equity Method Investees
Total Revenues
DD&A
Asset Impairments
Gain on Divestitures
Gain on Commodity Derivative Instruments
Income (Loss) from Continuing Operations Before
Income Taxes
Equity Method Investments
Additions to Long-Lived Assets
Goodwill at End of Year
Total Assets at End of Year (2)
Year Ended December 31, 2010
Revenues from Third Parties (1)
Reclassification from AOCL (3)
Income from Equity Method Investees
Total Revenues
DD&A
Asset Impairments
Gain on Divestitures
Gain on Commodity Derivative Instruments
Income (Loss) from Continuing Operations Before
Income Taxes
Equity Method Investments
Additions to Long-Lived Assets
Goodwill at End of Year
Total Assets at End of Year (2)
$
$
$
4,037
186
4,223
1,370
104
(154)
(75)
1,356
367
3,525
635
$
$ 2,339
—
2,339
929
73
(154)
(76)
806
121
2,046
635
1,343
186
1,529
255
—
—
1
1,074
230
447
—
17,509
11,199
3,063
$
$
3,211
193
3,404
878
757
(25)
(42)
$ 2,125
—
2,125
732
757
—
(74)
502
329
4,358
696
16,105
96
72
3,007
696
11,201
2,615
(20)
118
2,713
819
144
(113)
(157)
$ 1,893
(20)
—
1,873
719
119
(113)
(168)
848
285
2,725
696
12,846
713
—
1,796
696
9,091
592
193
785
69
—
—
32
561
257
618
—
2,728
349
—
118
467
39
—
—
11
355
285
612
—
2,270
$
$
$
178
—
178
111
31
—
—
9
—
869
—
2,572
307
—
307
25
—
—
—
228
—
687
—
1,751
191
—
—
191
22
25
—
—
119
—
270
—
919
177
—
177
75
—
—
—
(533)
16
163
—
675
187
—
187
52
—
(25)
—
(383)
—
46
—
425
182
—
—
182
39
—
—
—
(339)
—
47
—
566
(1) Revenues from third parties for all foreign countries, in total, were $1.7 billion in 2012, $1.1 billion in 2011, and $722 million in 2010.
141
Noble Energy, Inc.
Notes to Consolidated Financial Statements
(2) Long-lived assets located in all foreign countries, in total, were $4.2 billion, $3.2 billion, and $2.0 billion at December 31, 2012, 2011,
and 2010 respectively.
(3) Revenues for the year ended December 31, 2010 include decreases resulting from hedging activities. The decreases resulted from hedge
gains and losses that were deferred in AOCL, as a result of previous cash flow hedge accounting, and subsequently reclassified to
revenues. All hedge gains and losses had been reclassified to revenues by December 31, 2010.
Note 18. Concentration of Risk
Concentration of Market Risk The largest single non-affiliated purchasers of our production were as follows:
Year Ended December 31, 2012
Glencore Energy UK Ltd
Shell (1)
Year Ended December 31, 2011
Glencore Energy UK Ltd
Shell (1)
Year Ended December 31, 2010
Glencore Energy UK Ltd
Percentage of
Crude Oil
Sales
Percentage of
Total Oil, Gas
& NGL Sales
39%
17%
24%
17%
17%
31%
14%
16%
12%
11%
(1) Includes sales to both Shell Trading (US) Company and 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, natural gas and NGL 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, such as Alen,
offshore Equatorial Guinea, and Tamar and Leviathan, offshore Israel, 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 in the way of parental guarantees or letters of credit,
including our largest crude oil purchaser. However, we do not have all of our trade credit protected through guarantees or credit
support. Nonperformance by a trade creditor could result in losses. See Note 5. Allowance for Doubtful Accounts.
142
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 19. Additional Shareholders’ Equity Information
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 Awards, Net of Forfeitures
Shares, End of Period
Treasury Stock
Shares, Beginning of Period
Shares Received From Employees in Payment of Withholding Taxes Due on Vesting of
Shares of Restricted Stock
Rabbi Trust Shares Distributed and/or Sold
Shares, End of Period
Year Ended December 31,
2012
2011
196,656,846
1,265,231
426,665
195,440,048
837,096
379,702
198,348,742
196,656,846
18,736,520
18,650,064
141,124
(102,268)
186,556
(100,100)
18,775,376
18,736,520
Accumulated other comprehensive loss in the shareholders’ equity section of the balance sheet included:
Accumulated Other Comprehensive Loss
Interest
Rate
Cash Flow
Hedges
Oil and Gas
Cash Flow
Hedges
Pension-
Related and
Other
(millions)
December 31, 2009
Realized Amounts Reclassified Into Earnings
Net Change in Other
December 31, 2010
Realized Amounts Reclassified Into Earnings
Unrealized Change in Fair Value
December 31, 2011
Realized Amounts Reclassified Into Earnings
Unrealized Change in Fair Value
December 31, 2012
$
$
(12) $
12
—
—
—
—
—
—
—
— $
(2) $
1
(41)
(42)
1
15
(26)
1
—
(25) $
(61) $
3
(4)
(62)
4
(16)
(74)
6
(20)
(88) $
Total
(75)
16
(45)
(104)
5
(1)
(100)
7
(20)
(113)
All amounts in the table above are reported net of tax, using an effective income tax rate of 35%.
Note 20. 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.
CONSOL Carried Cost Obligation Based on the December 31, 2012 Henry Hub natural gas price strip, we forecast our
CONSOL Carried Cost Obligation will be suspended throughout the 2013 fiscal year. Therefore, specific payment dates for
funding cannot be determined at this time and are excluded from the minimum commitments table below. See Note 3.
Acquisitions and Divestitures.
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 $37 million in 2012, $31 million
in 2011, and $27 million in 2010.
143
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Minimum commitments as of December 31, 2012 consist of the following:
Drilling, Equipment,
and Purchase
Obligations
Transportation
and Gathering
Operating
Lease
Obligations
FPSO
Lease
Payments(1)
Total
(millions)
2013
2014
2015
2016
2017
2018 and Thereafter
Total
$
$
739
191
175
101
—
—
1,206
$
$
81
78
86
88
87
311
731
$
$
47
42
52
52
48
302
543
$
$
72
72
70
45
45
109
413
$
$
939
383
383
286
180
722
2,893
(1) Annual lease payments, net to our interest, exclude regular maintenance and operational costs. See Note 12. Long-Term Debt.
144
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 and natural gas reserves and exploration and
production activities.
Reserves
There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Crude oil and
natural gas 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 and natural gas that are ultimately recovered.
Economic producibility of reserves is dependent on the crude oil and natural gas prices used in the reserves estimate. We based
our December 31, 2012, 2011, and 2010 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. Declines
in crude oil or natural gas prices could result in negative reserves revisions.
Reserves Estimates 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 Vice President - Strategic Planning, Environmental Analysis & Reserves and certain members of
senior 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, 2012. See Items 1. and 2. Business and Properties
– Proved Reserves Disclosures.
Geographic Areas Our supplemental disclosures are grouped by geographic area, which include the United States, Equatorial
Guinea, Israel and Other International. Other International includes Cameroon, China, Cyprus, Ecuador (through November 24,
2010), Falkland Islands, North Sea, Nicaragua, Sierra Leone, Senegal/Guinea-Bissau and other new ventures. The North Sea
geographical segment is classified as discontinued operations in our consolidated financial statements.
Operations in China, Cyprus, Equatorial Guinea, and Sierra Leone are conducted in accordance with the terms of PSCs. In
Cameroon, we operate in accordance with the terms of a PSC and a mining concession. Operations in Nicaragua, the Falkland
Islands, the North Sea, Israel, and other foreign locations are conducted in accordance with concession agreements, permits or
licenses.
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 extract 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.
145
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Undeveloped Oil and Gas Reserves Proved 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 natural gas, natural gas liquids and crude oil reserves, refer to SEC Regulation S-X,
Rule 4-10(a)(6), (22) and (31).
146
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, Condensate and NGLs (MMBbls)
United
States (1)
Equatorial
Guinea
Other
Int'l (2)
Total
Proved Reserves as of:
December 31, 2009
Revisions of Previous Estimates (3)
Extensions, Discoveries and Other Additions (4)
Purchase of Minerals in Place (5)
Sale of Minerals in Place (6)
Production (7)
December 31, 2010
Revisions of Previous Estimates (3)
Extensions, Discoveries and Other Additions (4)
Purchase of Minerals in Place (5)
Sale of Minerals in Place (6)
Production (7)
December 31, 2011
Revisions of Previous Estimates (3)
Extensions, Discoveries and Other Additions (4)
Purchase of Minerals in Place (5)
Sale of Minerals in Place (6)
Production (7)
December 31, 2012
Proved Developed Reserves as of
December 31, 2009
December 31, 2010
December 31, 2011
December 31, 2012
Proved Undeveloped Reserves as of
December 31, 2009
December 31, 2010
December 31, 2011
December 31, 2012
(1) United States NGL proved reserves totaled:
209
15
25
23
(28)
(19)
225
(5)
43
—
—
(19)
244
(57)
106
—
(25)
(24)
244
122
119
134
130
87
106
110
114
92
1
26
—
—
(7)
112
2
—
—
—
(8)
106
9
—
—
—
(15)
100
49
43
60
60
43
69
46
40
35
(5)
3
—
—
(5)
28
(6)
2
—
—
(5)
19
—
1
—
(4)
(3)
13
23
21
13
8
12
7
6
5
336
11
54
23
(28)
(31)
365
(9)
45
—
—
(32)
369
(48)
107
—
(29)
(42)
357
194
183
207
198
142
182
162
159
United States NGL Reserves (MMBbls)
Proved Developed
Proved Undeveloped
December 31, 2009
December 31, 2010
December 31, 2011
December 31, 2012
27
38
49
42
16
23
24
30
Total Proved
43
61
73
72
(2) Other International includes China and the North Sea.
(3) The 2010 US revisions include the impacts of higher prices and additional NGLs recorded in Wattenberg, partially offset by the
reclassification of 16 MMBbls of PUD reserves to probable reserves, primarily in Wattenberg, as a result of the SEC's five year
development rule. The 2010 revisions to other international reserves are related to performance revisions in China and the North Sea.
The 2011 US revisions were primarily associated with reclassification of vertical PUDs to probable reserves in Wattenberg which are no
longer expected to be developed in five years due to shifting emphasis from vertical to horizontal development, partially offset by
147
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
positive revisions in other onshore US fields. International revisions are associated with performance revisions in China and the North
Sea.
The 2012 US revisions are primarily attributable to our decision to terminate the legacy vertical drilling program in Wattenberg and
focus on the horizontal development of the Niobrara formation. Equatorial Guinea revisions are associated with performance revisions
for the Aseng field. See Items 1. and 2. Business and Properties - Proved Undeveloped Reserves (PUDs).
(4) The 2010 increase in US proved reserves relates to continuing development of onshore assets, primarily in the DJ Basin. The 2010
increase in Equatorial Guinea reserves includes 26 MMBbl for the Alen field.
The 2011 increase is from development of onshore assets, primarily in the DJ Basin.
The 2012 increase in US reserves included an increase of 98 MMBbls in the DJ Basin and 8 MMBbls from Marcellus Shale
development. International increases were due primarily to additional development in China. See Items 1. and 2. Business and
Properties - Proved Undeveloped Reserves (PUDs).
(5) The 2010 increase relates to the DJ Basin asset acquisition. See Note 3. Acquisitions and Divestitures.
(6)
In 2010, we sold non-core, onshore US assets in the Mid-Continent and Illinois Basin.
In 2012 we sold non-core, onshore US and North Sea assets. See Note 3. Acquisitions and Divestitures.
(7) Equatorial Guinea production includes sales from the Alba field to the Alba LPG plant of 3 MMBbl in 2012, 2011 and 2010.
148
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:
Proved Reserves as of:
December 31, 2009
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, 2010
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, 2011
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, 2012
Proved Developed Reserves as of
December 31, 2009
December 31, 2010
December 31, 2011
December 31, 2012
Proved Undeveloped Reserves as of
December 31, 2009
December 31, 2010
December 31, 2011
December 31, 2012
United
States
1,534
(6)
140
139
(35)
(146)
1,626
(241)
326
406
—
(141)
1,976
(266)
601
—
(164)
(160)
1,987
1,114
1,156
1,195
1,042
420
470
781
945
Natural Gas and Casinghead Gas (Bcf)
Equatorial
Guinea
Other
Int'l (1)
Israel
940
12
—
—
—
(83)
869
7
—
—
—
(90)
786
2
16
—
—
(86)
718
638
597
497
514
302
272
289
204
234
(41)
1,698
—
—
(47)
1,844
—
488
—
—
(63)
2,269
(24)
42
—
—
(37)
2,250
191
145
83
18
43
1,699
2,186
2,232
196
(3)
—
—
(160)
(11)
22
(8)
—
—
—
(2)
12
—
—
—
(2)
(1)
9
192
19
11
8
4
3
1
1
Total
2,904
(38)
1,838
139
(195)
(287)
4,361
(242)
814
406
—
(296)
5,043
(288)
659
—
(166)
(284)
4,964
2,135
1,917
1,786
1,582
769
2,444
3,257
3,382
(1) Other International includes China, Ecuador (at December 31, 2009), and the North Sea. See Note 3. Acquisitions and Divestitures and
Note 4. Asset Impairments.
(2) The 2010 US revisions are a combination of increases from higher natural gas prices, which were more than offset by gas shrinkage
from additional NGLs recorded in Wattenberg and the reclassification of 85 Bcf of PUDs to probable reserves, primarily in Wattenberg,
as a result of the SEC's five year development rule. Equatorial Guinea’s positive revision in 2010 is primarily due to additional
production allowances related to LNG sales. Israel’s revisions in 2010 reflected a change in the likelihood that the Noa field would be
developed.
The 2011 US revisions were primarily associated with reclassification of vertical PUDs in Wattenberg which are no longer expected to
be developed in five years due to shifting activity level from vertical to horizontal development and revisions to onshore dry gas assets
due to reduced activity assumptions, performance, and price. International revisions are associated with performance revisions in the
North Sea.
The 2012 US revisions are primarily attributable to our decision to terminate the legacy vertical drilling program in Wattenberg and
focus on the horizontal development of the Niobrara formation and negative price revisions due to lower natural gas prices, partially
offset by improved well performance in the Marcellus Shale. International revisions are due to performance revisions in the Mari B
field. See Items 1. and 2. Business and Properties - Proved Undeveloped Reserves (PUDs).
149
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
(3) The 2010 increase in US proved reserves is due to continuing development of onshore assets, primarily in the DJ Basin, Piceance Basin,
and East Texas. The 2010 increase in Israel is due to the recording of initial reserves at the Tamar development.
The 2011 increase in the US is primarily due to active development programs in the DJ Basin and the Marcellus Shale. The increase in
Israel was primarily due to continuing appraisal at Tamar and includes reserves for Noa which we decided to develop (See Items 1. and
2. Business and Properties - Eastern Mediterranean).
The 2012 increase in US reserves includes 305 Bcf in the DJ Basin and 291 Bcf in the Marcellus Shale. The Equatorial Guinea increase
is due to additions at Aseng, and the Israel increase is due to additional appraisal activity at Tamar. See Items 1. and 2. Business and
Properties - Proved Undeveloped Reserves (PUDs).
(4) The increases relate to our DJ Basin asset acquisition in 2010 and our Marcellus Shale asset acquisition in 2011. See Note 3.
Acquisitions and Divestitures.
(5)
In 2010, we sold non-core, onshore US assets in the Mid-Continent and Illinois Basin. Other International sales in 2010 include 160 Bcf
due to the termination of the Block 3 PSC by the Ecuadorian government.
In 2012, we sold non-core, onshore US and North Sea assets. See Note 3. Acquisitions and Divestitures.
150
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Results of Operations for Oil and Gas Producing Activities (Unaudited) Aggregate results of operations for crude oil and
natural gas producing activities are as follows:
United
States
Equatorial
Guinea
Israel
Other
Int'l (1)
Total
(millions)
Year Ended December 31, 2012
Revenues
Production Costs (2)
Exploration Expense
DD&A
Asset Impairments
Income before Income Taxes
Income Tax Expense (3)
Results of Operations (4)
Year Ended December 31, 2011
Revenues
Production Costs (2)
Exploration Expense
DD&A
Asset Impairments
Income before Income Taxes
Income Tax Expense
Results of Operations (4)
Year Ended December 31, 2010
Revenues
Sales (5)
Sales to Affiliated Power Plant
Total Revenues
Production Costs (2)
Exploration Expense
DD&A
Asset Impairments
Income before Income Taxes
Income Tax Expense
Results of Operations (4)
$
$
$
$
$
$
2,339
539
225
929
73
573
201
372
2,124
453
116
732
757
66
24
42
1,874
—
1,874
449
130
719
119
457
160
297
$
$
$
$
$
$
1,343
105
3
255
—
980
245
735
592
71
67
70
—
384
96
288
349
—
349
50
7
39
—
253
63
190
$
$
$
$
$
$
178
31
—
111
31
5
4
1
307
26
6
25
—
250
72
178
191
—
191
15
11
22
25
118
21
97
$
$
$
$
$
$
$
384
105
210
75
—
(6)
74
(80) $
513
123
90
113
2
185
74
111
418
35
453
94
48
82
—
229
62
167
$
$
$
$
4,244
780
438
1,370
104
1,552
524
1,028
3,536
673
279
940
759
885
266
619
2,832
35
2,867
608
196
862
144
1,057
306
751
(1) Other International includes the North Sea, Ecuador (through November 24, 2010), China, Cameroon, Cyprus, Senegal/Guinea-Bissau,
Nicaragua, Falkland Islands, Sierra Leone and other new ventures. See Note 3. Acquisitions and Divestitures.
(2) Production costs consist of lease operating expense, production and ad valorem taxes, transportation expense, and general and
administrative expense supporting oil and gas operations.
(3) During 2012, we incurred exploration expense in currently non-commercial international locations; therefore, no tax benefit was
included in income tax expense associated with Other International as we cannot conclude it is more likely than not that some portion or
all of the deferred tax assets will be realized.
(4) Results of operations exclude the mark-to-market gain or loss on certain commodity derivative instruments not designated as cash flow
hedges, corporate overhead and interest costs. See Note 10. Derivative Instruments and Hedging Activities.
(5)
Includes impact resulting from applying cash flow hedge accounting for related commodity derivative instruments. See Note 10.
Derivative Instruments and Hedging Activities.
151
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities (Unaudited) (1)
Costs incurred in connection with crude oil and natural gas acquisition, exploration and development are as follows:
(millions)
Year Ended December 31, 2012
Property Acquisition Costs
Unproved (4)
Exploration Costs (5)
Development Costs (6)
Total Consolidated Operations
Company's share of CONE LLC development costs
Year Ended December 31, 2011
Property Acquisition Costs
Proved (3)
Unproved (4)
Total Acquisition Costs
Exploration Costs (5)
Development Costs (6)
Total Consolidated Operations
Company's share of CONE LLC development costs
Year Ended December 31, 2010
Property Acquisition Costs
Proved (3)
Unproved (4)
Total Acquisition Costs
Exploration Costs (5)
Development Costs (6)
Total Consolidated Operations
United
States
Equatorial
Guinea
Israel
Other
Int'l (2)
Total
$
$
$
$
$
$
$
$
68
335
1,839
2,242
55
392
942
1,334
241
1,511
3,086
60
352
304
656
306
964
1,926
$
$
$
$
$
$
— $
56
366
422
—
$
— $
—
—
54
499
553
—
$
— $
1
1
6
596
603
$
— $
125
718
843
—
$
— $
—
—
146
485
631
—
$
— $
—
—
52
236
288
$
$
28
173
70
271
$
— $
— $
40
40
152
37
229
$
— $
— $
—
—
54
75
129
$
96
689
2,993
3,778
55
392
982
1,374
593
2,532
4,499
60
352
305
657
418
1,871
2,946
(1) Costs incurred include capitalized and expensed items.
(2) Other International includes Cameroon, China, Cyprus, Ecuador (through November 24, 2010), Falkland Islands, the North Sea,
Senegal/Guinea-Bissau, Nicaragua, Sierra Leone and other new ventures. See Note 3. Acquisitions and Divestitures.
(3) Proved property acquisition costs include $386 million related to the Marcellus Shale asset acquisition in 2011 and $352 million related
to the DJ Basin asset acquisition in 2010.
(4)
(5)
2012 unproved property acquisition costs for the US include: $63 million related to expanding our position in the DJ Basin, $28 million
for deepwater Gulf of Mexico lease blocks, and $27 million related to other onshore US, offset by a downward purchase price
adjustments of $50 million related to our Marcellus Shale acquisition. 2012 unproved property acquisition costs for Other International
include $25 million related to our position in Falkland Islands
2011 unproved property acquisition costs include: $853 million related to the Marcellus Shale asset acquisition, $40 million related to
our position offshore Senegal/Guinea-Bissau (the AGC Profond block), $31 million related to additional acreage in the DJ Basin and $58
million related to other onshore US.
2010 unproved property acquisition costs include: $146 million related to the DJ Basin asset acquisition, $38 million for deepwater Gulf
of Mexico lease blocks and the remainder for other onshore US lease acquisitions primarily in Wattenberg.
2012 exploration costs include drilling and completion of $102 million in Israel, $71 million in Falkland Islands, $40 million in
Equatorial Guinea, $36 million in the DJ Basin, and $13 million in Cyprus.
2011 exploration costs include drilling and completion costs of $74 million in deepwater Gulf of Mexico, $146 million in Israel, $54
million in Equatorial Guinea, $59 million in Cyprus, $36 million in Senegal/Guinea-Bissau and $42 million in the DJ Basin.
2010 exploration costs include drilling and completion costs of $62 million in deepwater Gulf of Mexico and $41 million in Israel.
(6) Worldwide development costs include amounts spent to develop PUDs of approximately $1.8 billion in 2012, $1.4 billion in 2011 and
$1.1 billion in 2010.
152
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
US development costs include increases in asset retirement obligations of $73 million in 2012, $115 million in 2011, and $15 million
in 2010. Other international development costs include increases in asset retirement obligations of $72 million in 2012, $13 million in
2011, and $2 million in 2010.
Equatorial Guinea development costs include non-cash accruals related to estimated construction progress to date on an FSPO used in
the development of the Aseng field of $66 million in 2011 and $266 million in 2010. These capitalized costs were included in
development costs as the Aseng FPSO was constructed.
Capitalized Costs Relating to Oil and Gas Producing Activities (Unaudited) Aggregate capitalized costs relating to crude
oil and natural gas producing activities 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 (3)
Company's share of CONE LLC Net Capitalized Costs
December 31,
2012
2011
$
$
$
$
1,399
18,297
19,696
(6,252)
13,444
118
$
$
1,519
17,538
19,057
(6,417)
12,640
65
(1) Unproved oil and gas properties includes $740 million, of which $734 million is related to Marcellus Shale, at December 31, 2012, and
$874 million, of which $792 million is related to Marcellus Shale, at December 31, 2011, remaining from the allocation of costs to
unproved properties acquired in previous acquisitions.
(2) Proved oil and gas properties include asset retirement costs of $334 million and $310 million at December 31, 2012 and 2011,
(3)
respectively.
Includes $200 million of proved oil and gas properties and $160 million of accumulated DD&A related to the North Sea classified as
assets held for sale at December 31, 2012. See Note 3. Acquisitions and Divestitures.
153
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 for extractive activities. 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.
(millions)
December 31, 2012
Future Cash Inflows (2)
Future Production Costs (3)
Future Development Costs
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, 2011
Future Cash Inflows (2)
Future Production Costs (3)
Future Development Costs
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, 2010
Future Cash Inflows (2)
Future Production Costs (3)
Future Development Costs
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
United
States
Equatorial
Guinea
Israel
Other
Int'l (1)
Total
$
$
$
$
$
$
$
$
$
$
23,495
6,531
5,372
3,622
7,970
3,506
4,464
27,663
7,367
5,283
4,939
10,074
4,930
5,144
22,078
6,140
4,099
3,863
7,976
3,941
$
$
$
$
$
10,318
2,148
417
1,811
5,942
1,750
4,192
11,112
1,808
716
2,028
6,560
2,110
4,450
8,373
1,598
1,154
1,299
4,322
1,589
$
$
$
$
$
14,608
942
440
2,568
10,658
6,523
4,135
13,603
1,144
639
2,407
9,413
6,203
3,210
7,983
460
924
1,366
5,233
3,530
$
$
$
$
$
1,171
487
177
166
341
51
290
1,806
496
267
471
572
87
485
2,083
664
240
517
662
49,592
10,108
6,406
8,167
24,911
11,830
13,081
54,184
10,815
6,905
9,845
26,619
13,330
13,289
40,517
8,862
6,417
7,045
18,193
127
9,187
$
4,035
$
2,733
$
1,703
$
535
$
9,006
(1) Other International includes China and the North Sea. See Note 3. Acquisitions and Divestitures.
(2) The standardized measure of discounted future net cash flows does not include cash flows relating to anticipated future methanol sales.
(3) Production costs include oil and gas lease operating expense, production and ad valorem taxes, transportation expense and general and
administrative expense supporting oil and gas operations.
154
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:
United
States
Equatorial
Guinea
Israel
Other
Int'l (1)
Total
December 31, 2012
Average Crude Oil, Condensate and NGL Price
per Bbl
Average Natural Gas Price per Mcf
December 31, 2011
$
74.64
$
100.97
$
105.38
$
114.54
$
2.66
0.25
6.36
6.77
Average Crude Oil, Condensate and NGL Price
per Bbl
Average Natural Gas Price per Mcf
December 31, 2010
Average Crude Oil, Condensate and NGL Price
per Bbl
Average Natural Gas Price per Mcf
$
$
$
$
78.90
4.24
65.63
4.49
$
$
103.01
0.25
72.93
0.25
$
$
99.92
5.85
79.35
4.22
111.50
6.55
77.41
3.76
$
$
(1) Other International includes China and the North Sea. See Note 3. Acquisitions and Divestitures.
83.39
3.99
87.38
4.35
68.79
3.53
We estimate that a $1.00 per Bbl change in the average price of crude oil from the 12-month average price for 2012 would
change the discounted future net cash flows before income taxes by approximately $216 million. We estimate that a $0.10 per
Mcf change in the average price of natural gas from the 12-month average price for 2012 would change the discounted future
net cash flows before income taxes by approximately $229 million.
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 and natural gas 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 $1.8 billion in 2013, $1.5 billion in
2014 and $1.1 billion in 2015.
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 and natural gas 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.
Imbalance receivables and liabilities are as follows:
(millions)
Imbalance Receivables
Imbalance Liabilities
Year Ended December 31,
2012
2011
2010
$
$
29
25
$
28
22
25
18
Imbalance receivables and imbalance liabilities have been excluded from the standardized measure of discounted future net
cash flows.
155
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 and natural gas reserves are as follows:
(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
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
Sales of Minerals in Place
Accretion of Discount
Net Change in Income Taxes
Change in Timing of Estimated Future Production and Other
Year Ended December 31,
2012
2011
2010
$
13,289
$
9,006
$
4,932
(3,463)
(1,902)
1,811
1,042
2,988
(1,256)
—
(1,141)
1,860
732
(879)
(2,864)
4,926
2,039
(710)
2,529
(1,320)
115
(6)
1,278
(1,540)
(164)
(2,251)
3,115
2,820
(915)
1,869
33
646
(652)
722
(1,487)
174
Aggregate Change in Standardized Measure of Discounted Future Net Cash
Flows
(208)
4,283
4,074
Standardized Measure of Discounted Future Net Cash Flows, End of Year
$
13,081
$
13,289
$
9,006
156
Supplemental Quarterly Financial Information
(Unaudited)
Supplemental quarterly financial information is as follows:
(millions except per share amounts)
2012 (1)
Revenues
Income from Continuing Operations Before Income Taxes
Income from Continuing Operations
Discontinued Operations, Net of Tax
Net Income
Basic Earnings Per Share (3)
Income from Continuing Operations
Discontinued Operations, Net of Tax
Net Income
Diluted Earnings Per Share (3) (4)
Income from Continuing Operations
Discontinued Operations, Net of Tax
Net Income
2011 (2)
Revenues
Income (Loss) from Continuing Operations Before Income Taxes
Income (Loss) from Continuing Operations
Discontinued Operations, Net of Tax
Net Income (Loss)
Basic Earnings (Loss) Per Share (3)
Income from Continuing Operations
Discontinued Operations, Net of Tax
Net Income (Loss)
Diluted Earnings (Loss) Per Share (3) (4)
Income from Continuing Operations
Discontinued Operations, Net of Tax
Net Income (Loss)
March 31,
Quarter Ended
Sep 30,
June 30,
Dec 31,
Total
$
$
$
$
$
$
$
$
$
$
1,088
335
249
14
263
1.40
0.08
1.48
1.39
0.08
1.47
786
(31)
(34)
48
14
(0.20) $
0.28
0.08
(0.20) $
0.28
0.08
965
390
275
17
292
1.55
0.09
1.64
1.49
0.09
1.58
842
356
269
25
294
1.51
0.15
1.66
1.47
0.14
1.61
$
$
$
$
$
$
$
$
$
$
$
$
1,003
275
164
57
221
0.92
0.32
1.24
0.91
0.32
1.23
879
699
491
(50)
441
2.78
(0.28)
2.50
2.67
(0.28)
2.39
1,167
356
277
(26)
251
$ 4,223
1,356
965
62
1,027
$
$
1.56
(0.15)
1.41
1.54
(0.15)
1.39
5.43
0.34
5.77
5.37
0.34
5.71
897
(522)
(314)
18
(296)
$ 3,404
502
412
41
453
(1.77) $
0.10
(1.67)
2.34
0.23
2.57
(1.77) $
0.10
(1.67)
2.31
0.23
2.54
(1) First quarter 2012 included the following:
•
$96 million loss on commodity derivative instruments, including unrealized mark-to-market loss of $73 million (See
Note 10. Derivative Instruments and Hedging Activities).
Second quarter 2012 included the following:
•
•
$73 million asset impairment charges (See Note 4. Asset Impairments);
$276 million gain on commodity derivative instruments, including unrealized mark-to-market gain of $277 million
(See Note 10. Derivative Instruments and Hedging Activities); and
$9 million pre-tax gain on sale of non-core onshore US assets (See Note 3. Acquisitions and Divestitures).
Third quarter 2012 included the following:
•
$135 million loss on commodity derivative instruments, including unrealized mark-to-market loss of $131 million
(See Note 10. Derivative Instruments and Hedging Activities); and
$157 million pre-tax gain on sale of non-core onshore US assets (See Note 3. Acquisitions and Divestitures).
•
•
157
Supplemental Quarterly Financial Information
(Unaudited)
Fourth quarter 2012 included the following:
•
•
$31 million impairment charges (See Note 4. Asset Impairments);
$13 million pre-tax loss on sale of non-core onshore US asset, due to post closing adjustments (See Note 3.
Acquisitions and Divestitures); and
$30 million gain on commodity derivative instruments, including unrealized mark-to-market gain of $36 million (See
Note 10. Derivative Instruments and Hedging Activities).
(2) First quarter 2011 included the following:
•
•
$8 million impairment charges (See Note 4. Asset Impairments); and
$286 million loss on commodity derivative instruments, including unrealized mark-to-market loss of $303 million
(See Note 10. Derivative Instruments and Hedging Activities).
Second quarter 2011 included the following:
•
•
$131 million impairment charges (See Note 4. Asset Impairments);
$143 million gain on commodity derivative instruments, including unrealized mark-to-market gain of $142 million
(See Note 10. Derivative Instruments and Hedging Activities); and
$25 million pre-tax gain on divestitures due to the completed transfer of assets and exit from Ecuador (See Note 3.
Acquisitions and Divestitures).
•
•
Third quarter 2011 included the following:
•
$322 million gain on commodity derivative instruments, including unrealized mark-to-market gain of $300 million
(See Note 10. Derivative Instruments and Hedging Activities).
Fourth quarter 2011 included the following:
•
•
$620 million asset impairment charges (See Note 4. Asset Impairments); and
$137 million loss on commodity derivative instruments, including unrealized mark-to-market gain of $44 million (See
Note 10. Derivative Instruments and Hedging Activities).
The sum of the individual quarterly earnings (loss) per share amounts may not agree with year-to-date earnings per share as
each quarterly computation is based on the income or loss for that quarter and the weighted average number of shares
outstanding during that quarter.
Consistent with GAAP, when dilutive, deferred compensation gains or losses, net of tax, are excluded from net income
while the Noble Energy shares held in the rabbi trust are included in the diluted share count. For this reason, the diluted
earnings per share calculations for the three months ended June 30, 2012 excludes a deferred compensation gain of $7
million, net of tax, and for the three months ended June 30 and September 30, 2011 exclude deferred compensation gains
of $4 million and $12 million, respectively, net of tax.
(3)
(4)
158
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 are designed and effective 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 potential 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, 2012.
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.
159
Item 10. Directors, Executive Officers and Corporate Governance
PART III
The information required by this item is incorporated herein by reference to the 2013 Proxy Statement, which will be filed with
the SEC not later than 120 days subsequent to December 31, 2012.
Item 11. Executive Compensation
The information required by this item is incorporated herein by reference to the 2013 Proxy Statement, which will be filed with
the SEC not later than 120 days subsequent to December 31, 2012.
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 2013 Proxy Statement, which will be filed with
the SEC not later than 120 days subsequent to December 31, 2012.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this item is incorporated herein by reference to the 2013 Proxy Statement, which will be filed with
the SEC not later than 120 days subsequent to December 31, 2012.
Item 14. Principal Accounting Fees and Services
The information required by this item is incorporated herein by reference to the 2013 Proxy Statement, which will be filed with
the SEC not later than 120 days subsequent to December 31, 2012.
Item 15. Exhibits, Financial Statement Schedules
a) The following documents are filed as a part of this report:
PART IV
(3) Exhibits: The exhibits required to be filed by this Item 15 are set forth in the Index to Exhibits accompanying this
report.
160
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 7, 2013
Date: February 7, 2013
Date: February 7, 2013
NOBLE ENERGY, INC.
(Registrant)
By: /s/ Charles D. Davidson
Charles D. Davidson,
Chairman of the Board,
Chief Executive Officer and Director
By: /s/ Kenneth M. Fisher
Kenneth M. Fisher,
Senior 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/ Charles D. Davidson
Charles D. Davidson
/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/ Thomas J. Edelman
Thomas J. Edelman
/s/ Eric P. Grubman
Eric P. Grubman
/s/ Kirby L. Hedrick
Kirby L. Hedrick
/s/ Scott D. Urban
Scott D. Urban
/s/ William T. Van Kleef
William T. Van Kleef
Chairman of the Board,
Chief Executive Officer and Director
(Principal Executive Officer)
February 7, 2013
Senior Vice President, Chief Financial Officer
February 7, 2013
(Principal Financial Officer)
Vice President, Chief Accounting Officer and Controller
February 7, 2013
(Principal Accounting Officer)
Director
Director
Director
Director
Director
Director
Director
Director
161
February 7, 2013
February 7, 2013
February 7, 2013
February 7, 2013
February 7, 2013
February 7, 2013
February 7, 2013
February 7, 2013
Exhibit
Number
2.1
INDEX TO EXHIBITS
Exhibit **
— Asset Acquisition Agreement dated August 17, 2011 between CNX Gas Company LLC and Noble Energy,
Inc. including Annex I (Definitions) thereto, filed as Exhibit 2.1 to the Registrant’s Quarterly Report on
Form 10-Q for the quarter ended September 30, 2011 and incorporated herein by reference).
3.1
— Certificate of Incorporation, as amended through May 25, 2012, of the Registrant (filed as Exhibit 3.1 to
the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2012, and incorporated
herein by reference).
3.2
— By-Laws of Noble Energy, Inc. as amended through June 1, 2009 (filed as Exhibit 3.1 to the Registrant’s
Current Report on Form 8-K (Date of Event: February 17, 2009) filed February 19, 2009 and incorporated
herein by reference).
4.1
— Certificate of Designations of Series A Junior Participating Preferred Stock of the Registrant dated
August 27, 1997 (filed as Exhibit A of Exhibit 4.1 to the Registrant’s Registration Statement on Form 8-A
filed on August 28, 1997 and incorporated herein by reference).
4.2
— Certificate of Designations of Series B Mandatorily Convertible Preferred Stock of the Registrant dated
November 9, 1999 (filed as Exhibit 3.4 to the Registrant’s Annual Report on Form 10-K for the year ended
December 31, 1999 and incorporated herein by reference).
4.3
— Indenture dated as of February 27, 2009 between Noble Energy, Inc. and Wells Fargo Bank, National
Association, as Trustee, relating to the Registrant’s 8¼% Notes Due March 1, 2019 (filed as Exhibit 4.1 to
the Registrant’s Current Report on Form 8-K (Date of Event: February 24, 2009) filed February 27, 2009
and incorporated herein by reference).
4.4
— First Supplemental Indenture dated as of February 27, 2009, 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 8¼% Notes Due March 1, 2019 (including the form of 2019 Notes) (filed as Exhibit 4.2 to the
Registrant’s Current Report on Form 8-K (Date of Event: February 24, 2009) filed February 27, 2009 and
incorporated herein by reference).
4.5
— Indenture dated as of October 14, 1993 between the Registrant and U.S. Trust Company of Texas, N.A., as
Trustee, relating to the Registrant’s 7¼% Notes Due 2023, including form of the Registrant’s 7¼% Notes
Due 2023 (filed as Exhibit 4.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended
September 30, 1993 and incorporated herein by reference).
4.6
4.7
4.8
4.9
— Indenture relating to Senior Debt Securities dated as of April 1, 1997 between the Registrant and U.S. Trust
Company of Texas, N.A., as Trustee (filed as Exhibit 4.1 to the Registrant’s Quarterly Report on Form 10-
Q for the quarter ended March 31, 1997 and incorporated herein by reference).
— First Indenture Supplement relating to $250 million of the Registrant’s 8% Senior Notes Due 2027 dated as
of April 1, 1997 between the Registrant and U.S. Trust Company of Texas, N.A., as Trustee (filed as
Exhibit 4.2 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1997 and
incorporated herein by reference).
— Second Indenture Supplement, between the Company and U.S. Trust Company of Texas, N.A. as trustee,
relating to $100 million of the Registrant’s 7¼% Senior Debentures Due 2097 dated as of August 1, 1997
(filed as Exhibit 4.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1997
and incorporated herein by reference).
— Third Indenture Supplement relating to $200 million of the Registrant’s 5¼% Notes due 2014 dated
April 19, 2004 between the Company and the Bank of New York Trust Company, N.A., as successor
trustee to U.S. Trust Company of Texas, N.A. (filed as Exhibit 4.1 to the Company’s Registration
Statement on Form S-4 (Registration No. 333-116092) and incorporated herein by reference).
4.10
— Second Supplemental Indenture dated as of February 18, 2011, to Indenture dated as of February 27, 2009
4.11
—
between Noble Energy, Inc. and Wells Fargo Bank, National Association, as Trustee, relating to senior debt
securities of Noble Energy, Inc. (including the form of 2041 Notes) (filed as Exhibit 4.1 to the Registrant’s
Current Report on Form 8-K (Date of Event: February 15, 2011) filed February 22, 2011 and incorporated
herein by reference).
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 senior debt
securities of Noble Energy, Inc. (including the form of 2021 Notes) (filed as Exhibit 4.1 to the Registrant’s
Current Report on Form 8-K (Date of Event: December 5, 2011) filed December 8, 2011 and incorporated
herein by reference).
162
Exhibit
Number
10.1*
— 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 and incorporated
herein by reference).
Exhibit **
10.2*
— 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 and incorporated herein by reference).
10.3*
— 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 Event:
February 1, 2005) filed February 7, 2005 and incorporated herein by reference).
10.4*
— 1988 Nonqualified Stock Option Plan for Non-Employee Directors of the Registrant, as amended and
restated, effective as of April 27, 2004 (filed as Exhibit 10.2 to the Registrant’s Quarterly Report on
Form 10-Q for the quarter ended June 30, 2004 and incorporated herein by reference).
10.5*
— Form of Indemnity Agreement entered into between the Registrant and each of the Registrant’s directors
and bylaw officers (filed as Exhibit 10.18 to the Registrant’s Annual Report on Form 10-K for the year
ended December 31, 1995 and incorporated herein by reference).
10.6*
10.7
— Amendment to the Noble Energy, Inc. Change of Control Severance Plan for Executives dated effective
February 1, 2011 (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Event:
February 1, 2011), filed February 4, 2011 and incorporated herein by reference).
— $3.0 billion five-year 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 Event: October 14, 2011) filed October 18, 2011 and incorporated
herein by reference).
10.8*
— 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 and incorporated herein by reference).
10.9*
— 2005 Stock Plan for Non-Employee Directors of Noble Energy, Inc. (filed as Exhibit 10.1 to the
Registrant’s Current Report on Form 8-K (Date of Event: April 26, 2005) filed April 29, 2005 and
incorporated herein by reference).
10.10* — 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 and incorporated herein by reference).
10.11* — Amendment to the 2005 Stock Plan for Non-Employee Directors of Noble Energy, Inc. (effective
September 1, 2008) (filed as Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter
ended September 30, 2008 and incorporated herein by reference).
10.12* — Amendment to the 2005 Stock Plan for Non-Employee Directors of Noble Energy, Inc. dated effective
March 17, 2011 (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Event:
March 17, 2011) filed March 22, 2011 and incorporated herein by reference).
10.13* — 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 Event: January 27,
2009) filed on February 2, 2009 and incorporated herein by reference).
10.14* — Form of Restricted Stock Agreement under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock
Plan, (filed as Exhibit 10.14 to the Registrant’s Annual Report on Form 10-K for the year ended December
31, 2009 and incorporated herein by reference).
10.15* — Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan (as amended through April 26, 2011),
(filed as exhibit 10.1 to Registrant’s Current Report on Form 8-K (Date of Event: April 26, 2011) filed
April 27, 2011 and incorporated herein by reference).
10.16* — Noble Energy, Inc. Change of Control Severance Plan for Executives (as amended effective January 1,
2008), (filed as Exhibit 10.40 to the Registrant’s Annual Report on Form 10-K for the year ended
December 31, 2007 and incorporated herein by reference).
10.17* — 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 and
incorporated herein by reference).
10.18* — 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 Event: February 1, 2011),
filed February 4, 2011 and incorporated herein by reference).
163
Exhibit
Number
10.19*
— 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 and
incorporated herein by reference).
Exhibit **
10.20
— Gas Sale and Purchase Agreement dated March 14, 2012, by and between Noble Energy Mediterranean
10.21
10.22
10.23
Ltd. and 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 and incorporated herein by reference).
— 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, and 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 and incorporated
herein by reference).
— 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 Company's Current Report on Form 8-K (Date of
Event: September 28, 2012), filed October 2, 2012 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 Company's Current Report on Form 8-K (Date of Event:
September 28, 2012), filed October 2, 2012 and incorporated herein by reference).
10.24*
— Form of Stock Option Agreement under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock
Plan, filed herewith.
10.25*
— Form of Restricted Stock Agreement (two-year vested) under the Noble Energy, Inc. 1992 Stock Option
and Restricted Stock Plan, filed herewith.
10.26*
— Form of Restricted Stock Agreement (for inducement awards) under the Noble Energy, Inc. 1992 Stock
Option and Restricted Stock Plan, filed herewith.
10.27*
— Form of Restricted Stock Agreement (performance-vested) under the Noble Energy, Inc. 1992 Stock
Option and Restricted Stock Plan, filed herewith.
12.1
14.1
21
23.1
23.2
31.1
31.2
32.1
32.2
99.1
— Calculation of ratio of earnings to fixed charges, filed herewith.
— Noble Energy, Inc. Code of Business Conduct and Ethics (filed as Exhibit 14.1 to the Registrant's Annual
Report on Form 10-K for the year ended December 31, 2011 and incorporated herein by reference).
— 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.
— Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002 (18 U.S.C. Section 7241), filed herewith.
— Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002 (18 U.S.C. Section 7241), filed herewith.
— Certification of the Company’s Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002 (18 U.S.C. Section 1350), filed herewith.
— Certification of the Company’s Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002 (18 U.S.C. Section 1350), filed herewith.
— 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.
Copies of exhibits will be furnished upon prepayment of 25 cents per page. Requests should be addressed to the Senior
Vice President and Chief Financial Officer, Noble Energy, Inc., 100 Glenborough Drive, Suite 100, Houston, Texas
77067.
164
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