⁽¹⁾The remaining performance obligations are estimated utilizing the contractual base or floor price provision in effect. Our future revenues from the sale of natural gas under these associated contracts will vary from the amounts presented above due to components of variable consideration above the contractual base or floor provision, such as index-based escalations and market price changes.


⁽¹⁾	The remaining performance obligations are estimated utilizing the contractual base or floor price provision in effect. Our future revenues from the sale of natural gas under these associated contracts will vary from the amounts presented above due to components of variable consideration above the contractual base or floor provision, such as index-based escalations and market price changes.

MIDSTREAM REVENUE ARRANGEMENTS

Midstream Services Arrangements Our Midstream segment revenues are derived from fixed fee contract arrangements for gathering, transportation and storage services. We have determined that our performance obligations for the provision of such services are satisfied over time using volumes delivered as the measure of progress. ASC 606 adoption did not have an impact on the recognition, measurement and presentation of our midstream revenues and expenses.

Crude Oil Purchase and Sale Arrangements – US As part of the Saddle Butte acquisition in first quarter 2018, we acquired a pipeline and associated third party contracts which include transactions for the purchase and sale of crude oil with varying counterparties. Revenues and expenses from the sales and purchases are recorded on a gross basis as we act as a principal in these transactions by assuming control of the purchased commodity before it is transferred to the customer. The purchases and sales of crude oil are recorded at the prevailing market prices.

Recently Issued Accounting Standards

Leases In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2016-02 (ASU 2016-02): Leases. The standard requires lessees to recognize ~~assets~~a right of use asset and ~~liabilities~~lease liability on the balance sheet for the rights and obligations created by ~~leases with terms of more than 12 months.~~leases. ASU 2016-02 also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. In ~~January 2018, the FASB issued Accounting Standards Update No. 2018-01 (ASU 2018-01):~~ ~~Land Easement Practical Expedient for Transition to Topic 842~~, to provide an optional practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under Topic 840. In July 2018, the FASB issued Accounting Standards Update No. 2018-10 (ASU 2018-10): ~~Codification Improvements to Topic 842, Leases, to clarify application of certain aspects of the standard and to remove inconsistencies within the guidance. Furthermore, in~~ July 2018, the FASB issued Accounting Standards Update No. 2018-11 (ASU 2018-11): Leases (Topic 842): Targeted Improvements, which provides for ~~another transition method, in addition to the existing~~an alternative transition method by allowing entities to initially apply the new leases standard at the adoption date (such as January 1, 2019) and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption ~~(i.e. comparative~~(comparative periods presented in the financial statements will continue to be in accordance with current GAAP (Topic 840, Leases)). The standard will be effective for annual and interim periods beginning after December 15, 2018, with earlier application permitted.

In the normal course of business, we enter into capital and operating lease agreements to support our exploration and development operations and lease assets, such as drilling rigs, platforms, ~~storage facilities,~~ field services and well equipment, ~~pipeline capacity,~~ office space and other assets. We will adopt the new standard on the effective date of January 1, ~~2019.~~2019, using a modified retrospective approach as permitted under ASU 2018-11. We plan to make certain elections allowing us to not reassess contracts that commenced prior to adoption of the standard, not recognize right of use assets or lease liabilities associated with leases of terms less than 12 months, and account for existing land easements under our current accounting policy.

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

Depreciation, Depletion and Amortization ~~DD&A~~Depreciation, depletion and amortization (DD&A) expense for our E&P operations was as follows:



(millions, except unit rate)	Total		United States		Eastern Mediter- ranean		West Africa		Other Int'l
Three Months Ended September 30, 2018
DD&A Expense	$	456	$	414	$	16	$	25	$	1
Unit Rate per BOE ⁽¹⁾	$	14.64	$	18.05	$	4.34	$	5.53	$	—
Three Months Ended September 30, 2017
DD&A Expense	$	502	$	442	$	18	$	41	$	1
Unit Rate per BOE ⁽¹⁾	$	15.79	$	19.72	$	4.11	$	8.19	$	—
Nine Months Ended September 30, 2018
DD&A Expense	$	1,336	$	1,214	$	44	$	77	$	1
Unit Rate per BOE ⁽¹⁾	$	14.12	$	17.41	$	4.00	$	5.55	$	—
Nine Months Ended September 30, 2017
DD&A Expense	$	1,502	$	1,326	$	58	$	114	$	4
Unit Rate per BOE ⁽¹⁾	$	14.73	$	18.02	$	4.58	$	7.23	$	—

(millions, except unit rate) Total United
States Eastern
Mediter- ranean
West
Africa
Other Int'l
Three Months Ended June 30, 2018
DD&A Expense $ 435
$ 394
$ 15
$ 26
$ —
Unit Rate per BOE ⁽¹⁾
$ 14.10
$ 17.51
$ 4.41
$ 5.25
$ —
Three Months Ended June 30, 2017
DD&A Expense $ 486
$ 427
$ 19
$ 39
$ 1
Unit Rate per BOE ⁽¹⁾
$ 13.32
$ 15.89
$ 4.62
$ 7.11
$ —
Six Months Ended June 30, 2018
DD&A Expense $ 880
$ 800
$ 28
$ 52
$ —
Unit Rate per BOE ⁽¹⁾
$ 13.87
$ 17.10
$ 3.82
$ 5.56
$ —
Six Months Ended June 30, 2017
DD&A Expense $ 999
$ 886
$ 37
$ 74
$ 2
Unit Rate per BOE ⁽¹⁾
$ 14.25
$ 17.32
$ 4.52
$ 6.88
$ —

~~Table of Contents~~⁽¹⁾Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.


⁽¹⁾	~~Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.~~

Total DD&A expense for ~~second~~third quarter and ~~the~~ first ~~six~~nine months of 2018 decreased as compared with 2017 due to the following:

year-end ~~reserve~~2017 proved reserves additions, primarily in US onshore due to enhanced well design and completion techniques in our horizontal drilling program, ~~as well as reserve additions~~ in the Tamar field due to well results and geological evaluation, and globally due to positive commodity price revisions;

~~the Marcellus Shale upstream divestiture in second quarter 2017, which reduced DD&A expense by $99 million and $118 million for second quarter and the first six months of 2018, respectively;~~

lower sales volumes in Gulf of Mexico due to natural field decline and classification of the assets as held for sale in first quarter 2018, resulting in the cessation of DD&A expense, together resulting in decreases of ~~$62~~$60 million and ~~$109~~$169 million for ~~second~~third quarter and ~~the~~ first ~~six~~nine months of 2018, respectively; and

reclassification of a 7.5% working interest in the Tamar field, offshore Israel, as ~~asset~~assets held for sale at December 31, 2017, resulting in the cessation of DD&A expense and decreases of $3$4 million and $7$11 million for ~~second~~third quarter and ~~the~~ first ~~six~~nine months of 2018, respectively;

partially offset by:

higher sales volumes in the Delaware Basin, which more than doubled, due to increased development activities subsequent to the Clayton Williams Energy Acquisition in second quarter 2017;

~~increased development activities in the southern area of Gates Ranch in the Eagle Ford Shale;~~ and

higher sales volumes from the Tamar field, offshore Israel, due to higher domestic demand.

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The unit rate per BOE for ~~second~~third quarter and first nine months of 2018 decreased, as compared with 2017, ~~increased~~primarily due to ~~increased development activity and capital program~~the decrease in ~~the Delaware Basin resulting in a higher depletable basis. The unit rate per BOE for the first six months of 2018, as compared~~total DD&A expense combined with ~~2017, decreased due to~~ the sale of higher-cost production from the Gulf of Mexico ~~assets.~~assets in second quarter 2018. This decrease is partially offset by increased development activity in the ~~sale~~Delaware Basin resulting in a higher depletable basis and the sales of lower-cost production from ~~the sale of~~our 7.5% ~~Tamar~~ interest in the Tamar field in first quarter 2018 and ~~the sale of~~ the Marcellus Shale upstream assets in second quarter 2017. ~~In addition, an increase~~

Loss (Gain) on Divestitures, Net Loss (gain) on divestitures, net, relates primarily to the gain recognized on the first quarter 2018 sale of a 7.5% interest in ~~reserves as~~the Tamar field, partially offset by the loss recognized on the sale of ~~December 31, 2017~~our Gulf of Mexico assets in ~~Equatorial Guinea also contributed to a decline in unit rate per BOE.~~second quarter 2018. See Item 1. Financial Statements – Note 3. Acquisitions and Divestitures.

Other Operating Expense (Income), Net See Item 1. Financial Statements – Note 2. Basis of Presentation and Item 1. Financial Statements – Note 11. Segment Information for discussion of other operating expense (income) items for ~~second~~third quarter and ~~the~~ first ~~six~~nine months of 2018 as compared with 2017.

Loss (Gain) on Commodity Derivative Instruments Loss (gain) on commodity derivative instruments includes (i) cash settlements ~~(received)~~paid or ~~paid~~(received) relating to our crude oil and natural gas commodity derivative contracts; and (ii) non-cash ~~(increases)~~decreases or ~~decreases~~(increases) in the fair values of our crude oil and natural gas commodity derivative contracts.

For the first ~~six~~nine months of 2018, loss on commodity derivative instruments included:

net cash settlement payment of ~~$93~~$160 million; and

net non-cash increase of ~~$235~~$323 million in the fair value of our net commodity derivative liability, primarily driven by increases in the forward commodity price curve for crude oil.

For the first ~~six~~nine months of 2017, gain on commodity derivative instruments included:

net cash settlement receipt of ~~$14~~$18 million; and

net non-cash increase of ~~$153~~$127 million in the fair value of our net commodity derivative asset, primarily driven by changes in the forward commodity price curves for both crude oil and natural gas.

See Item 1. Financial Statements – Note 4. Derivative Instruments and Hedging Activities and Item 1. Financial Statements – Note 6. Fair Value Measurements and Disclosures.

MIDSTREAM

The Midstream segment develops, owns, operates ~~develops~~ and acquires domestic midstream infrastructure assets, or invests in other midstream entities, with current focus areas being the DJ and Delaware Basins.

Recent Development

Noble Midstream Partners Salt Creek Joint Venture On October 2, 2018, Noble Midstream Partners entered into a letter of intent with Salt Creek to form a 50/50 joint venture on the construction of a 200 MBbl/d day pipeline system in the Delaware Basin. The 95-mile, 20-inch diameter pipeline system will originate in Pecos County, Texas, with additional connections in Reeves County and Winkler County, Texas. The project footprint will be served by a combination of in-field crude oil gathering lines and a trunkline to a hub in Wink, Texas.

Salt Creek has commenced construction of the pipeline, with an expected operational date in the second quarter of 2019. Execution of definitive agreements and closing of the transaction is expected to occur in the fourth quarter of 2018. At closing, the project will be underpinned by approximately 180,000 dedicated gross acres and nearly 100 miles of pipeline in Pecos, Reeves, Ward and Winkler Counties, Texas, including an in-basin crude oil dedication of approximately 70,000 gross acres by us. Capital investment from Noble Midstream Partners is expected to total approximately $60 million to $80 million over five years.

Results of Operations

Highlights for our Midstream segment were as follows:

~~Second~~Third Quarter 2018 Significant Midstream Operating Highlights and Financial Results Included:

commenced gathering services on an initial well for a third-party Delaware Basin producer;

net proceeds of approximately $248 million received, and gain of $198 million recognized, on the sale of our investment in ~~the Mustang IDP area in the DJ Basin;~~CNX Midstream Partners common units;

~~completed construction~~pre-tax income of ~~the Collier~~$268 million, as compared with pre-tax income of $58 million for third quarter 2017; and ~~Billy Miner Train II CGFs in the Delaware Basin;~~

capital expenditures of $69 million, as compared with $96 million for third quarter 2017.

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secured long-term dedications, from existing and new third party customers, for the Black Diamond system, a large, integrated gathering system in the DJ Basin acquired in the Saddle Butte acquisition; and

~~received a third party producer's activity set and development plan for Delaware Basin acreage, with gathering services expected to commence in late 2018.~~

~~Second Quarter 2018 Midstream Financial Results Included:~~

~~net proceeds of approximately $135 million received, and gain of $109 million recognized, on the sale of a portion of our investment in CNX Midstream Partners common units;~~

~~pre-tax income of $175 million, as compared with pre-tax income of $58 million for second quarter 2017; and~~

~~capital expenditures, excluding acquisitions, of $157 million, as compared with $88 million for second quarter 2017.~~

Following is a summarized statement of operations for our Midstream segment:


	Three Months Ended June 30,					Six Months Ended June 30,					Three Months Ended September 30,					Nine Months Ended September 30,
(millions)	2018			2017		2018			2017		2018			2017		2018			2017
Midstream Services Revenues – Third Party	$	15		$	4	$	28		$	4	$	21		$	7	$	49		$	12
Sales of Purchased Oil	42			—		64			—		46			—		110			—
Income from Equity Method Investees	13			13		25			28		10			13		35			41
Intersegment Revenues	85			69		166			127		91			72		257			198
Total Revenues	155			86		283			159		168			92		451			251
Operating Costs and Expenses	27			23		61			42		30			24		96			66
Depreciation and Amortization	22			5		38			10		24			10		62			20
Gain on Divestitures	(109		)	—		(305		)	—
Gain on Divestitures, Net											(198		)	—		(503		)	—
Purchased Oil	40			—		61			—		44			—		106			—
Total (Income) Expense	(20		)	28		(145		)	52		(100		)	34		(239		)	86
Income Before Income Taxes	$	175		$	58	$	428		$	107	$	268		$	58	$	690		$	165

⁽¹⁾~~2017 acquisition costs include $1.6 billion related to the Clayton Williams Energy Acquisition and $246 million related to the Delaware Basin acquisition.~~

⁽²⁾2017 acquisition costs include $724 million of proved properties and $59 million of asset retirement obligations acquired in the Clayton Williams Energy Acquisition and $58 million related to the Delaware Basin asset acquisition.


⁽¹⁾	Unproved and Proved property acquisition costs for the three months ended September 30, 2017 included purchase price adjustments related to the Clayton Williams Energy Acquisition.


⁽²⁾	Unproved property acquisition costs for the first nine months of 2018 relate to leasing activity. Unproved property acquisition costs for the first nine months of 2017 included $1.6 billion related to the Clayton Williams Energy Acquisition and $246 million related to the Delaware Basin asset acquisition.


⁽³⁾	Proved property acquisition costs for the first nine months of 2017 included $724 million of proved properties and $59 million of asset retirement obligations acquired in the Clayton Williams Energy Acquisition and $58 million related to the Delaware Basin asset acquisition.


⁽⁴⁾	Midstream expenditures for first nine months of 2018 included $206 million related to the Saddle Butte acquisition. Midstream expenditures for the first nine months of 2017 included $68 million related to the Clayton Williams Energy Acquisition.


⁽⁵⁾	Investment in equity method investee for the first nine months of 2017 represents our contribution to the Advantage Joint Venture, in which Noble Midstream Partners owns a 50% interest.

Table of Contents Midstream expenditures for the six months ended June 30, 2018 include $206 million related to the Saddle Butte acquisition. Midstream expenditures for the first six months of 2017 include $67 million related to the Clayton Williams Energy Acquisition.

⁽⁴⁾~~2017 costs represent our contribution to the Advantage Joint Venture, in which Noble Midstream Partners owns a 50% interest.~~

~~Development~~

Exploration and development costs for ~~second~~third quarter and ~~the~~ first ~~six~~nine months of 2018 increased as compared with ~~second~~third quarter and ~~the~~ first ~~six~~nine months of 2017 due to increased US onshore activity and Leviathan development activities. ~~Year to date~~For the first nine months of 2018, exploration and development costs include approximately ~~$1.1~~$1.6 billion for US onshore E&P operations and approximately ~~$350~~$514 million for Leviathan. The increase in ~~development~~ costs was partially offset by a decrease due to the 2017 Marcellus Shale divestiture. In addition, ~~midstream~~Midstream capital spending, exclusive of acquisitions, increased in first nine months of 2018 due to the construction of gathering systems in the DJ and Delaware Basins.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

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. See Results of Operations - E&P, above.

Derivative Instruments Held for Non-Trading Purposes 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.

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At ~~June~~September 30, 2018, we had various open commodity derivative instruments related to crude oil and natural gas. Changes in fair value of commodity derivative instruments are reported in earnings in the period in which they occur. Our open commodity derivative instruments were in a net liability position with a fair value of ~~$306~~$394 million. Based on the ~~June~~September 30, 2018 published commodity futures price curves for the underlying commodities, a hypothetical price increase of 10% per Bbl for crude oil and 10% per MMBtu for natural gas would increase the fair value of our net commodity derivative liability by approximately ~~$280~~$236 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 1. Financial Statements – Note 4. Derivative Instruments and Hedging Activities.

Interest Rate Risk

Changes in interest rates affect the amount of interest we pay on certain of our borrowings and the amount of interest we earn on our short-term investments.

At ~~June~~September 30, 2018, we had approximately $6.4 billion (excluding capital lease obligations) of long-term debt outstanding, net of unamortized discount and debt issuance costs. Of this amount, $5.8 billion was fixed-rate debt, net of unamortized discount and debt issuance costs, with a weighted average interest rate of 5.06%. Although near term changes in interest rates may affect the fair value of our fixed-rate debt, they do not expose us to interest rate risk or cash flow loss.

However, we are exposed to interest rate risk related to our interest-bearing cash and cash equivalents balances. As of ~~June~~September 30, 2018, our cash and cash equivalents totaled ~~$621~~$720 million, approximately ~~46%~~29% of which was invested in money market funds and short-term investments with major financial institutions.

In addition, borrowings under the Revolving Credit Facility, Noble Midstream Services Revolving Credit Facility, Noble Midstream Services Term Loan Credit Facility and Leviathan Term Loan Facility are subject to variable interest rates which expose us to the risk of earnings or cash flow loss due to potential increases in market interest rates. A change in the interest rate applicable to our variable-rate debt could expose us to additional interest cost. While we currently have no interest rate derivative instruments as of ~~June~~September 30, 2018, we may invest in such instruments in the future in order to mitigate interest rate risk. A change in the interest rate applicable to our short-term investments or amounts, if any, outstanding under the ~~Noble Revolving Credit Facility, Noble Midstream Services Revolving Credit Facility or Leviathan Term Loan Facility~~above-named facilities would have a de minimis ~~impact.~~impact on our consolidated net income. See Item 1. Financial Statements – Note 5. Debt.

Foreign Currency Risk

The US dollar is considered the functional currency for each of our international operations. Substantially all of our international crude oil, natural gas and NGL production is sold pursuant to US dollar denominated contracts. Transactions, such as operating costs and administrative expenses that are paid in a foreign currency, are remeasured into US dollars and recorded in the financial statements at prevailing currency exchange rates. Certain monetary assets and liabilities, for example certain local working capital items, are denominated in a foreign currency and remeasured into US dollars. A reduction in the value of the US dollar against currencies of other countries in which we have material operations could result in the use of additional cash to settle operating, administrative and tax liabilities. ~~Furthermore, our investment in Tamar Petroleum is denominated and settled in New Israeli Shekels.~~

Net transaction gains and losses were de minimis for the ~~second~~third quarter and ~~the~~ first ~~six~~nine months of 2018.

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.

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Disclosure Regarding Forward-Looking Statements

This quarterly report on Form 10-Q contains forward-looking statements within the meaning of the federal securities laws. Forward-looking statements give our current expectations or forecasts of future events. These forward-looking statements include, among others, the following:

our growth strategies;

our future results of operations;

our liquidity and ability to finance our exploration, development and acquisitions activities;

our ability to satisfy contractual commitments, including utilization or commercialization of firm transportation commitments in the Marcellus Shale;

our ability to make and integrate acquisitions;

our ability to successfully and economically explore for and develop crude oil, natural gas and NGL resources;

anticipated trends in our business;

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market conditions in the oil and gas industry;

the impact of governmental fiscal regulation, including federal, state, local, and foreign host regulations, and/or terms, such as those involving the protection of the environment or marketing of production, as well as other regulations; and

access to resources.

Any such projections or statements reflect Noble Energy’s views (as of the date such projects were published or such statements were made) about future events and financial performance. No assurances can be given that such events or performance will occur as projected, and actual results may differ materially from those projected. Important factors that could cause the actual results to differ materially from those projected include, without limitation, the volatility in commodity prices for crude oil and natural gas, the presence or recoverability of estimated reserves, the ability to replace reserves, environmental risks, drilling and operating risks, exploration and development risks, information technology and security risks, competition, government regulation or other action, the ability of management to execute its plans to meet its goals and other risks inherent in Noble Energy’s business that are detailed in its Securities and Exchange Commission filings.

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 our 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 included in our Annual Report on Form 10-K for the year ended December 31, 2017 and in this quarterly report on Form 10-Q, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements. Our Annual Report on Form 10-K for the year ended December 31, 2017 is available on our website at www.nblenergy.com.

Item 4. Controls and Procedures

Based on the evaluation of our disclosure controls and procedures by our principal executive officer and our principal financial officer, as of the end of the period covered by this quarterly report, each of them has concluded that our disclosure controls and procedures (as defined in Rule 13a-15(e) and Rule 15d-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act)), are effective. There were no changes in internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f) and 15d-15(f)) that occurred during the quarter covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. These forms can also be obtained from the SEC by calling 1-800-SEC-0330. Alternatively, you may access these reports at the SEC’s website at www.sec.gov.

Part II. Other Information

Item 1. Legal Proceedings

See discussion of legal proceedings in Part I. Financial Information, Item 1. Financial Statements - Note ~~12. Commitments and~~13. Contingencies of this Form 10-Q, which is incorporated by reference into this Part II. Item 1, as well as discussion in Item 3. Legal Proceedings, of our Annual Report on Form 10-K for the year ended December 31, 2017.

Item 1A. Risk Factors

There have been no material changes from the risk factors disclosed in Item 1A. Risk Factors of our Annual Report on Form 10-K for the year ended December 31, ~~2017.~~2017, other than the following:

Colorado Proposition #112, if approved by voters on November 6, 2018, could significantly limit, or in some cases prevent, the future development of crude oil and natural gas in areas where we currently conduct operations.

Current regulations in the state of Colorado require oil and gas development to maintain a 500-foot set-back from certain structures and a 1,000-foot set-back from certain high-occupancy buildings. However, on November 6, 2018, Colorado voters will decide whether to adopt Proposition #112, which, if passed, would increase the set-back zone for new “oil and gas development” to 2,500 feet. The term “oil and gas development” in Proposition #112 is defined to include oil and gas exploration, drilling, production and processing activities, as well as hydraulic fracturing, the reentry of an oil or gas well previously plugged or abandoned, flowlines and the treatment of waste associated with such exploration, drilling, production and processing activities. As proposed under Proposition #112, the set-back increase would be applicable to “occupied structures” and “vulnerable areas”. “Vulnerable areas” is defined to include playgrounds, permanent sports fields, public parks and open spaces, public drinking water sources, reservoirs, lakes, rivers, perennial and intermittent streams, creeks, and any other area designated as such by the state or local government; however, the proposition provides no guidance on when or how such governments may exercise this authority. If adopted, Proposition #112 is expected to take effect upon official certification of election results, to be self-executing, and to apply to new oil and gas development that is permitted on or after the date of certification; it is not expected to apply to previously permitted wells, including drilled but uncompleted wells. The Colorado Oil and Gas Conservation Commission estimates that adoption of Proposition #112 would result in approximately 85% of Colorado's non-federal land surface becoming unavailable for new oil and gas development. In Weld County alone, 78% of surface land (85% of non-federal land) would appear to be off-limits to new oil and gas development.

The adoption of Proposition #112 could significantly limit, or in some cases prevent, the future development of crude oil and natural gas in areas where we currently conduct operations. Moreover, Proposition #112 could simultaneously curtail demand for our midstream services within the state. As such, our future drilling activities in Colorado could be significantly limited or hindered, and the amounts that we are ultimately able to produce from our undeveloped reserves in Colorado could be adversely affected.

In addition, if Proposition #112 is adopted, or other regulatory measures go into effect, we may incur additional costs to comply with any of its requirements or may experience delays and/or curtailment in the permitting or pursuit of our exploration, development, or production activities. Such compliance costs and delays, curtailments, limitations, or prohibitions could have a material adverse effect on our cash flows, results of operations, financial condition, and liquidity. Adoption of Proposition #112 could result in a decrease in our proved undeveloped reserves and even a material impairment of our Colorado assets.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

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The following table sets forth, for the periods indicated, our share repurchase activity:

Period
Total Number of
Shares
Purchased ⁽¹⁾

Average
Price Paid
Per Share

Total Number of
Shares Purchased
as Part of Publicly
Announced Plans or
Programs⁽²⁾

Approximate Dollar
Value of Shares that
May Yet Be
Purchased Under the
Plans or Programs
(millions)
4/1/2018 - 4/30/2018 216
$ 31.72
—

5/1/2018 - 5/31/2018 837,995
32.84
837,418

6/1/2018 - 6/30/2018 941,779
35.65
941,502

Total 1,779,990
$ 34.33
1,778,920
$ 620



Period	Total Number of Shares Purchased ⁽¹⁾	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs⁽²⁾	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
					(millions)
7/1/2018 - 7/31/2018	70	$	37.23	—
8/1/2018 - 8/31/2018	1,366,585	29.72		1,366,533
9/1/2018 - 9/30/2018	2,044,590	30.28		2,044,590
Total	3,411,245	$	30.05	3,411,123	$	517


⁽¹⁾	Includes stock repurchases of ~~1,070~~122 shares during the period relating to common stock received by us from employees for the payment of withholding taxes due on shares of common stock issued under stock-based compensation plans.


⁽²⁾	During ~~second~~third quarter 2018, we repurchased and retired ~~1.8 million~~3,411,123 shares of common stock at an average purchase price of ~~$35.15~~$30.07 per share pursuant to the $750 million share repurchase program, authorized by our Board of Directors, which expires December 31, 2020.

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Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

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Item 6. Exhibits



Exhibit Number		Exhibit*

2.1		Agreement and Plan of Merger, dated as of January 13, 2017, by and among Noble Energy, Inc., Wild West Merger Sub Inc., NBL Permian LLC, and Clayton Williams Energy, Inc. (filed as Exhibit 2.1 to the Registrant’s Current Report on Form 8-K (Date of Report: January 13, 2017) filed on January 17, 2017 and incorporated herein by reference).

2.2		Agreement and Plan of Merger, dated as of May 10, 2015, by and among Noble Energy, Inc., Bluebonnet Merger Sub Inc. and Rosetta Resources Inc. (filed as Exhibit 2.1 of the Registrant’s Current Report on Form 8-K (Date of Report: May 10, 2015) filed on May 11, 2015 and incorporated herein by reference).

2.3		Exchange Agreement, executed October 29, 2016, by and between CNX Gas Company LLC and Noble Energy, Inc. (filed as Exhibit 2.3 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2016 and incorporated herein by reference).

3.1		Restated Certificate of Incorporation of Noble Energy Inc., (filed as Exhibit 3.3 to the Registrant’s Current Report on Form 8-K (Date of Report: July 26, 2016) filed on July 28, 2016 and incorporated herein by reference).

3.2		By-Laws of Noble Energy, Inc. (as amended through January 30, 2018) (filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K (Date of Report: January 30, 2018) filed on February 1, 2018 and incorporated herein by reference).

3.3		Certificate of Elimination of the Series A Junior Participating Preferred Stock of Noble Energy, Inc. (filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K (Date of Report: July 26, 2016) filed on July 28, 2016 and incorporated herein by reference).

3.4		Certificate of Elimination of the Series B Mandatorily Convertible Preferred Stock of Noble Energy, Inc. (filed as Exhibit 3.2 to the Registrant’s Current Report on Form 8-K (Date of Report: July 26, 2016) filed on July 28, 2016 and incorporated herein by reference).

10.1*10.1		Noble Energy, Inc. Short-Term Incentive Plan ~~filed herewith.~~(filed as Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018 and incorporated herein by reference).

12.1		Calculation of ratio of earnings to fixed charges, filed herewith.

31.1		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.

31.2		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.

32.1		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), furnished herewith.

32.2		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), furnished herewith.

101.INS		Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL 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

Table of Contents



*	~~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 Executive Vice President and Chief Financial Officer, Noble Energy, Inc., 1001 Noble Energy Way, Houston, Texas 77070.

~~Table of Contents~~

Signatures

Pursuant to the requirements 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.



		NOBLE ENERGY, INC.
		(Registrant)

Date	~~August 3,~~November 1, 2018	/s/ Kenneth M. Fisher
		Kenneth M. Fisher Executive Vice President, Chief Financial Officer

5354



Delaware		73-0785597
(State or other jurisdiction of incorporation or organization)		(I.R.S. employer identification number)
1001 Noble Energy Way
Houston, Texas		77070
(Address of principal executive offices)		(Zip Code)
(281) 872-3100 (Registrant’s telephone number, including area code)



Large accelerated filer x	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o	Emerging growth company o
		~~(Do not check if a smaller reporting company)~~



Part I. Financial Information	3

Item 1. Financial Statements	3

Consolidated Statements of Operations and Comprehensive Income	3

Consolidated Balance Sheets	4

Consolidated Statements of Cash Flows	5

Consolidated Statements of Equity	6

Notes to Consolidated Financial Statements	7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	2931

Item 3. Quantitative and Qualitative Disclosures About Market Risk	4650

Item 4. Controls and Procedures	4851

Part II. Other Information	4851

Item 1. Legal Proceedings	4851

Item 1A. Risk Factors	4851

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	4852

Item 3. Defaults Upon Senior Securities	5052

Item 4. Mine Safety Disclosures	5052

Item 5. Other Information	5052

Item 6. Exhibits	5153

Signatures	5354


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017			2018			2017			2018			2017
Revenues
Oil, NGL and Gas Sales	$	1,100		$	1,017		$	2,273		$	2,011		$	1,136		$	907		$	3,409		$	2,918
Income from Equity Method Investees and Other	130			42			243			84
Sales of Purchased Oil and Gas and Other													137			53			380			137
Total	1,230			1,059			2,516			2,095			1,273			960			3,789			3,055
Costs and Expenses
Production Expense	292			283			613			586			273			280			886			866
Exploration Expense	29			30			64			72			25			64			89			136
Depreciation, Depletion and Amortization	465			503			933			1,031			485			523			1,418			1,554
Loss on Marcellus Shale Upstream Divestiture	—			2,322			—			2,322
Loss on Marcellus Shale Exit Activities													—			4			—			2,326
Gain on Divestitures, Net	(78		)	—			(666		)	—			(193		)	—			(859		)	—
Asset Impairments	—			—			168			—			—			—			168			—
General and Administrative	105			103			209			202			107			102			316			304
Other Operating Expense, Net	74			118			144			147
Other Operating Expense (Income), Net													78			(15		)	222			132
Total	887			3,359			1,465			4,360			775			958			2,240			5,318
Operating Income (Loss)	343			(2,300		)	1,051			(2,265		)	498			2			1,549			(2,263		)
Other (Income) Expense
Loss (Gain) on Commodity Derivative Instruments	249			(57		)	328			(167		)	155			22			483			(145		)
Interest, Net of Amount Capitalized	73			96			146			183			70			88			216			271
Other Non-Operating Expense (Income), Net	11			(5		)	24			(6		)
Other Non-Operating (Income) Expense, Net													(34		)	100			(10		)	94
Total	333			34			498			10			191			210			689			220
Income (Loss) Before Income Taxes	10			(2,334		)	553			(2,275		)	307			(208		)	860			(2,483		)
Income Tax Expense (Benefit)	16			(836		)	(15		)	(824		)	59			(93		)	44			(917		)
Net (Loss) Income and Comprehensive (Loss) Income Including Noncontrolling Interests	(6		)	(1,498		)	568			(1,451		)
Net Income (Loss) and Comprehensive Income (Loss) Including Noncontrolling Interests													248			(115		)	816			(1,566		)
Less: Net Income and Comprehensive Income Attributable to Noncontrolling Interests	17			14			37			25			21			21			58			46
Net (Loss) Income and Comprehensive Income (Loss) Attributable to Noble Energy	$	(23	)	$	(1,512	)	$	531		$	(1,476	)
Net Income (Loss) and Comprehensive Income (Loss) Attributable to Noble Energy													$	227		$	(136	)	$	758		$	(1,612	)

Net (Loss) Income Attributable to Noble Energy per Common Share
Net Income (Loss) Attributable to Noble Energy per Common Share
Basic	$	(0.05	)	$	(3.20	)	$	1.09		$	(3.27	)	$	0.47		$	(0.28	)	$	1.57		$	(3.47	)
Diluted	$	(0.05	)	$	(3.20	)	$	1.09		$	(3.27	)	$	0.47		$	(0.28	)	$	1.56		$	(3.47	)
Weighted Average Number of Common Shares Outstanding
Basic	484			472			485			452			482			487			484			464
Diluted	484			472			487			452			484			487			486			464


	June 30, 2018			December 31, 2017			September 30, 2018			December 31, 2017
ASSETS
Current Assets
Cash and Cash Equivalents	$	621		$	675		$	720		$	675
Accounts Receivable, Net	743			748			698			748
Other Current Assets	187			780			309			780
Total Current Assets	1,551			2,203			1,727			2,203
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method of Accounting)	28,334			29,678			29,029			29,678
Property, Plant and Equipment, Other	896			879			893			879
Total Property, Plant and Equipment, Gross	29,230			30,557			29,922			30,557
Accumulated Depreciation, Depletion and Amortization	(11,313		)	(13,055		)	(11,677		)	(13,055		)
Total Property, Plant and Equipment, Net	17,917			17,502			18,245			17,502
Other Noncurrent Assets	984			461			774			461
Goodwill	1,402			1,310			1,401			1,310
Total Assets	$	21,854		$	21,476		$	22,147		$	21,476
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable – Trade	$	1,308		$	1,161		$	1,239		$	1,161
Other Current Liabilities	745			578			885			578
Total Current Liabilities	2,053			1,739			2,124			1,739
Long-Term Debt	6,555			6,746			6,571			6,746
Deferred Income Taxes	970			1,127			983			1,127
Other Noncurrent Liabilities	995			1,245			1,075			1,245
Total Liabilities	10,573			10,857			10,753			10,857
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 per share; 1 Billion Shares Authorized; 526 Million and 529 Million Shares Issued, respectively	5			5
Common Stock - Par Value $0.01 per share; 1 Billion Shares Authorized; 523 Million and 529 Million Shares Issued, respectively							5			5
Additional Paid in Capital	8,329			8,438			8,249			8,438
Accumulated Other Comprehensive Loss	(28		)	(30		)	(27		)	(30		)
Treasury Stock, at Cost; 39 Million Shares	(731		)	(725		)	(731		)	(725		)
Retained Earnings	2,677			2,248			2,850			2,248
Noble Energy Share of Equity	10,252			9,936			10,346			9,936
Noncontrolling Interests	1,029			683			1,048			683
Total Equity	11,281			10,619			11,394			10,619
Total Liabilities and Equity	$	21,854		$	21,476		$	22,147		$	21,476


	Attributable to Noble Energy																				Attributable to Noble Energy
	Common Stock		Additional Paid in Capital			Accumulated Other Comprehensive Loss			Treasury Stock at Cost			Retained Earnings			Non- controlling Interests			Total Equity			Common Stock		Additional Paid in Capital			Accumulated Other Comprehensive Loss			Treasury Stock at Cost			Retained Earnings			Non- controlling Interests			Total Equity
December 31, 2017	$	5	$	8,438		$	(30	)	$	(725	)	$	2,248		$	683		$	10,619		$	5	$	8,438		$	(30	)	$	(725	)	$	2,248		$	683		$	10,619
Net Income	—		—			—			—			531			37			568			—		—			—			—			758			58			816
Stock-based Compensation	—		46			—			—			—			—			46			—		63			—			—			—			—			63
Dividends (21 cents per share)	—		—			—			—			(102		)	—			(102		)
Dividends (32 cents per share)																					—		—			—			—			(156		)	—			(156		)
Purchase and Retirement of Common Stock	—		(130		)	—			—			—			—			(130		)	—		(233		)	—			—			—			—			(233		)
Clayton Williams Energy Acquisition	—		(25		)	—			—			—			—			(25		)	—		(25		)	—			—			—			—			(25		)
Distributions to Noncontrolling Interest Owners	—		—			—			—			—			(22		)	(22		)	—		—			—			—			—			(35		)	(35		)
Contributions from Noncontrolling Interest Owners	—		—			—			—			—			331			331			—		—			—			—			—			348			348
Other	—		—			2			(6		)	—			—			(4		)	—		6			3			(6		)	—			(6		)	(3		)
June 30, 2018	$	5	$	8,329		$	(28	)	$	(731	)	$	2,677		$	1,029		$	11,281
September 30, 2018																					$	5	$	8,249		$	(27	)	$	(731	)	$	2,850		$	1,048		$	11,394

December 31, 2016	$	5	$	6,450		$	(31	)	$	(692	)	$	3,556		$	312		$	9,600		$	5	$	6,450		$	(31	)	$	(692	)	$	3,556		$	312		$	9,600
Net (Loss) Income	—		—			—			—			(1,476		)	25			(1,451		)	—		—			—			—			(1,612		)	46			(1,566		)
Clayton Williams Energy Acquisition	—		1,876			—			(25		)	—			—			1,851			—		1,876			—			(25		)	—			—			1,851
Stock-based Compensation	—		65			—			—			—			—			65			—		80			—			—			—			—			80
Dividends (20 cents per share)	—		—			—			—			(92		)	—			(92		)
Dividends (30 cents per share)																					—		—			—			—			(141		)	—			(141		)
Issuance of Noble Midstream Partners Common Units, Net of Offering Costs	—		—			—			—			—			138			138			—		—			—			—			—			138			138
Distributions to Noncontrolling Interest Owners	—		—			—			—			—			(12		)	(12		)	—		—			—			—			—			(19		)	(19		)
Other	—		8			1			(10		)	—			—			(1		)	—		9			2			(11		)	—			—			—
June 30, 2017	$	5	$	8,399		$	(30	)	$	(727	)	$	1,988		$	463		$	10,098
September 30, 2017																					$	5	$	8,415		$	(29	)	$	(728	)	$	1,803		$	477		$	9,943


(millions)	July - Dec 2018		2019		2020		Total		Oct - Dec 2018		2019		2020		Total
Natural Gas Revenues ⁽¹⁾	$	107	$	137	$	169	$	413	$	54	$	137	$	169	$	360


⁽²⁾	~~Expense relates~~Amounts relate to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain ~~commitments.~~commitments primarily in the DJ Basin for 2018 and in the DJ Basin and Marcellus Shale for 2017 (prior to the Marcellus Shale upstream divestiture in second quarter 2017).


⁽³⁾	Gain resulted from downward asset retirement obligation revisions in locations where we have no remaining assets. See Note 8. Asset Retirement Obligations.


⁽²⁾	Balance at September 30, 2018 represents Noble Midstream Partners collateral on letters of credit. Balance at December 31, 2017 represents amount held in escrow pending closing of the Saddle Butte acquisition. See Note 3. Acquisitions and Divestitures.


⁽³⁾	~~Includes $49 million for~~Amount relates to our investment in shares of Tamar Petroleum Ltd. See Note 3. Acquisitions and Divestitures and Note 6. Fair Value Measurements and Disclosures.


⁽⁴⁾	In 2018, we sold our units in CNX Midstream Partners ~~LP.~~LP, which was previously recorded as an equity method investment. At December 31, 2017, this investment was included in assets held for sale. See Note 3. Acquisitions and Divestitures and Note 6. Fair Value Measurements and Disclosures.


⁽⁴⁾⁽⁵⁾	Amount relates to intangible assets acquired in the Saddle Butte acquisition and is net of ~~$14~~$22 million of accumulated amortization. See Note 3. Acquisitions and Divestitures.



(millions)
Fair Value of Common Stock Issued	$	1,851
Plus: Cash Consideration Paid to Clayton Williams Energy Stockholders	637
Total Purchase Price	$	2,488
Plus Liabilities Assumed by Noble Energy:
Accounts Payable	99
Other Current Liabilities	38
Long-Term Deferred Tax Liability	515
Long-Term Debt	595
Asset Retirement Obligations	63
Total Purchase Price Plus Liabilities Assumed	$	3,798


⁽¹⁾	No pro forma adjustments were made for the period as Clayton Williams Energy operations are included in our historical results.


				Swaps					Collars									Swaps					Collars
Settlement Period	Type of Contract	Index	Bbls Per Day	Weighted Average Differential			Weighted Average Fixed Price		Weighted Average Short Put Price		Weighted Average Floor Price		Weighted Average Ceiling Price		Type of Contract	Index	Bbls Per Day	Weighted Average Differential			Weighted Average Fixed Price		Weighted Average Short Put Price		Weighted Average Floor Price		Weighted Average Ceiling Price
2018	Swaps	NYMEX WTI	66,000	$	—		$	60.30	$	—	$	—	$	—	Swaps	NYMEX WTI	66,000	$	—		$	60.30	$	—	$	—	$	—
2018	Collars	NYMEX WTI	18,000	—			—		—		50.42		58.82		Collars	NYMEX WTI	18,000	—			—		—		50.42		58.82
2018	Three-Way Collars	NYMEX WTI	10,000	—			—		45.50		52.50		69.09		Three-Way Collars	NYMEX WTI	10,000	—			—		45.50		52.50		69.09
2018	Three-Way Collars	Dated Brent	3,000	—			—		40.00		50.00		70.41		Three-Way Collars	Dated Brent	3,000	—			—		40.00		50.00		70.41
2018	Swaps	ICE Brent	2,000	—			59.00		—		—		—		Swaps	ICE Brent	2,000	—			59.00		—		—		—
2018	Collars	ICE Brent	2,000	—			—		—		50.00		55.25		Collars	ICE Brent	2,000	—			—		—		50.00		55.25
2018	Three-Way Collars	ICE Brent	5,000	—			—		43.00		50.00		59.50		Three-Way Collars	ICE Brent	5,000	—			—		43.00		50.00		59.50
2018	Basis Swaps	⁽¹⁾	20,000	(2.30		)	—		—		—		—		Basis Swaps	⁽¹⁾	20,000	(2.30		)	—		—		—		—
2019	Swaps	NYMEX WTI	44,000	—			58.37		—		—		—		Swaps	NYMEX WTI	44,000	—			58.37		—		—		—
2019	Three-Way Collars	NYMEX WTI	6,000	—			—		50.00		60.00		72.75		Three-Way Collars	NYMEX WTI	11,000	—			—		52.05		62.05		75.84
2019	Swaps	ICE Brent	5,000	—			57.00		—		—		—		Swaps	ICE Brent	5,000	—			57.00		—		—		—
2019	Three-Way Collars	ICE Brent	3,000	—			—		43.00		50.00		64.07		Three-Way Collars	ICE Brent	3,000	—			—		43.00		50.00		64.07
2019	Basis Swaps	⁽¹⁾	27,000	(3.23		)	—		—		—		—		Basis Swaps	⁽¹⁾	27,000	(3.23		)	—		—		—		—
2020	Swaption ⁽²⁾	NYMEX WTI	5,000	—			61.79		—		—		—		Swaption ⁽²⁾	NYMEX WTI	5,000	—			61.79		—		—		—
2020	Basis Swaps	⁽¹⁾	15,000	(5.01		)	—		—		—		—		Basis Swaps	⁽¹⁾	15,000	(5.01		)	—		—		—		—


				Swaps		Collars									Swaps					Collars
Settlement Period	Type of Contract	Index	MMBtu Per Day	Weighted Average Fixed Price		Weighted Average Short Put Price		Weighted Average Floor Price		Weighted Average Ceiling Price		Type of Contract	Index	MMBtu Per Day	Weighted Average Differential			Weighted Average Fixed Price		Weighted Average Short Put Price		Weighted Average Floor Price		Weighted Average Ceiling Price
2018	Three-Way Collars	NYMEX HH	120,000	$	—	$	2.50	$	2.88	$	3.65	Three-Way Collars	NYMEX HH	120,000	$	—		$	—	$	2.50	$	2.88	$	3.65
2019												Three-Way Collars	NYMEX HH	104,000	—			—		2.25		2.65		2.95
2019												Basis Swaps	⁽¹⁾	52,000	(0.74		)	—		—		—		—


	June 30, 2018					December 31, 2017					September 30, 2018					December 31, 2017
(millions, except percentages)	Debt			Interest Rate		Debt			Interest Rate		Debt			Interest Rate		Debt			Interest Rate
Revolving Credit Facility, due March 9, 2023	$	—		—	%	$	230		2.27	%	$	—		—	%	$	230		2.27	%
Noble Midstream Services Revolving Credit Facility, due March 9, 2023	530			3.25	%	85			2.75	%	50			3.32	%	85			2.75	%
Noble Midstream Services Term Loan Credit Facility, due July 31, 2021											500			3.17	%	—			—	%
Leviathan Term Loan Facility, due February 23, 2025	—			—	%	—			—	%	—			—	%	—			—	%
Senior Notes, due May 1, 2021 ⁽¹⁾	—			—	%	379			5.63	%	—			—	%	379			5.63	%
Senior Notes, due December 15, 2021	1,000			4.15	%	1,000			4.15	%	1,000			4.15	%	1,000			4.15	%
Senior Notes, due October 15, 2023	100			7.25	%	100			7.25	%	100			7.25	%	100			7.25	%
Senior Notes, due November 15, 2024	650			3.90	%	650			3.90	%	650			3.90	%	650			3.90	%
Senior Notes, due April 1, 2027	250			8.00	%	250			8.00	%	250			8.00	%	250			8.00	%
Senior Notes, due January 15, 2028	600			3.85	%	600			3.85	%	600			3.85	%	600			3.85	%
Senior Notes, due March 1, 2041	850			6.00	%	850			6.00	%	850			6.00	%	850			6.00	%
Senior Notes, due November 15, 2043	1,000			5.25	%	1,000			5.25	%	1,000			5.25	%	1,000			5.25	%
Senior Notes, due November 15, 2044	850			5.05	%	850			5.05	%	850			5.05	%	850			5.05	%
Senior Notes, due August 15, 2047	500			4.95	%	500			4.95	%	500			4.95	%	500			4.95	%
Other Senior Notes and Debentures ⁽²⁾	92			7.13	%	92			7.13	%	92			7.13	%	92			7.13	%
Capital Lease Obligations	241			—	%	273			—	%	234			—	%	273			—	%
Total	6,663					6,859					6,676					6,859
Unamortized Discount	(23		)			(24		)			(23		)			(24		)
Unamortized Premium ⁽¹⁾	—					12					—					12
Unamortized Debt Issuance Costs	(38		)			(40		)			(38		)			(40		)
Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs	6,602					6,807					6,615					6,807
Less Amounts Due Within One Year
Less Amounts Due Within One Year:
Capital Lease Obligations	(47		)			(61		)			(44		)			(61		)
Long-Term Debt Due After One Year	$	6,555				$	6,746				$	6,571				$	6,746


⁽¹⁾	Level 1 measurements are fair value measurements which use quoted market prices (unadjusted) in active markets for identical assets or liabilities. We use Level 1 inputs when available as Level 1 inputs generally provide the most reliable evidence of fair value.


⁽¹⁾	We have entered into crude oil basis swap contracts in order to establish a fixed amount for the differential between pricing in Midland, Texas, and Cushing, Oklahoma. The weighted average differential represents the amount of reduction to Cushing, Oklahoma prices for the notional volumes covered by the basis swap contracts.


⁽²⁾	We have entered into certain derivative contracts (swaptions), which give counterparties the right, but not the obligation, to enter into swap agreements with us on the option expiration dates.


⁽¹⁾	We have entered into natural gas basis swap contracts in order to establish a fixed amount for the differential between index pricing for Colorado Interstate Gas and NYMEX Henry Hub. The weighted average differential represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes covered by the basis swap contracts.


	Fair Value of Derivative Instruments												Fair Value of Derivative Instruments
	Asset Derivative Instruments						Liability Derivative Instruments						Asset Derivative Instruments						Liability Derivative Instruments
	June 30, 2018			December 31, 2017			June 30, 2018			December 31, 2017			September 30, 2018			December 31, 2017			September 30, 2018			December 31, 2017
(millions)	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity Derivative Instruments	Current Assets	$	29	Current Assets	$	2	Current Liabilities	$	250	Current Liabilities	$	58	Current Assets	$	—	Current Assets	$	2	Current Liabilities	$	294	Current Liabilities	$	58
	Noncurrent Assets	—		Noncurrent Assets	—		Noncurrent Liabilities	85		Noncurrent Liabilities	15		Noncurrent Assets	—		Noncurrent Assets	—		Noncurrent Liabilities	100		Noncurrent Liabilities	15
Total		$	29		$	2		$	335		$	73		$	—		$	2		$	394		$	73


⁽¹⁾	In second quarter 2018, we redeemed all of the Senior Notes due May 1, 2021, and expensed the associated premium. See Redemption of Senior Notes, below.


⁽²⁾	Includes $8 million of Senior Notes due June 1, 2024 and $84 million of Senior Debentures due August 1, 2097. The weighted average interest rate for these instruments is 7.13%.


	Fair Value Measurements Using														Fair Value Measurements Using
(millions)	Quoted Prices in Active Markets (Level 1) ⁽¹⁾			Significant Other Observable Inputs (Level 2) ⁽²⁾			Significant Unobservable Inputs (Level 3) ⁽³⁾		Adjustment ⁽⁴⁾			Fair Value Measurement			Quoted Prices in Active Markets (Level 1) ⁽¹⁾			Significant Other Observable Inputs (Level 2) ⁽²⁾			Significant Unobservable Inputs (Level 3) ⁽³⁾		Adjustment ⁽⁴⁾			Fair Value Measurement
June 30, 2018
September 30, 2018
Financial Assets:
Mutual Fund Investments	$	57		$	—		$	—	$	—		$	57		$	58		$	—		$	—	$	—		$	58
Commodity Derivative Instruments	—			72			—		(43		)	29			—			35			—		(35		)	—
Investment in Tamar Petroleum Ltd. (38,495,575 Shares)⁽⁵⁾	—			150			—		—			150			—			165			—		—			165
Financial Liabilities:
Commodity Derivative Instruments	—			(378		)	—		43			(335		)	—			(429		)	—		35			(394		)
Portion of Deferred Compensation Liability Measured at Fair Value	(73		)	—			—		—			(73		)	(73		)	—			—		—			(73		)
Stock Based Compensation Liability Measured at Fair Value	(12		)	—			—		—			(12		)	(14		)	—			—		—			(14		)
December 31, 2017
Financial Assets:
Mutual Fund Investments	$	57		$	—		$	—	$	—		$	57		$	57		$	—		$	—	$	—		$	57
Commodity Derivative Instruments	—			7			—		(5		)	2			—			7			—		(5		)	2
Financial Liabilities:
Commodity Derivative Instruments	—			(78		)	—		5			(73		)	—			(78		)	—		5			(73		)
Portion of Deferred Compensation Liability Measured at Fair Value	(71		)	—			—		—			(71		)	(71		)	—			—		—			(71		)
Stock Based Compensation Liability Measured at Fair Value	(10		)	—			—		—			(10		)	(10		)	—			—		—			(10		)


⁽²⁾	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.


⁽³⁾	Level 3 measurements are fair value measurements which use unobservable inputs.


⁽⁴⁾	Amount represents the impact of netting provisions within our master agreements that allow us to net cash settle asset and liability positions with the same counterparty.


⁽⁵⁾	~~As of June 30, 2018, the closing price on the TASE of publicly traded and unrestricted shares of Tamar Petroleum Ltd. was $4.60 per share.~~


⁽¹⁾	~~During second quarter 2018, we sold 7.5 million common units, reducing our ownership in CNX Midstream Partners. See~~ ~~Note 3. Acquisitions and Divestitures~~.


⁽¹⁾	As of September 30, 2018, the fair value of long-term debt approximates the carrying amount, primarily due to the current rising interest rate environment.


⁽²⁾	Excludes unamortized discount, premium, debt issuance costs and capital lease obligations.


(millions)	Six Months Ended June 30, 2018			Nine Months Ended September 30, 2018
Capitalized Exploratory Well Costs, Beginning of Period	$	520		$	520
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves	4			7
Divestitures ⁽¹⁾	(167		)	(168		)
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves	(1		)	(1		)
Capitalized Exploratory Well Costs Charged to Expense	—			—
Capitalized Exploratory Well Costs, End of Period	$	356		$	358


⁽¹⁾	Represents costs primarily related to Gulf of Mexico assets.


⁽¹⁾	Accretion expense is included in depreciation, depletion and amortization (DD&A) expense in the consolidated statements of operations.


				Oil and Gas Exploration and Production								Midstream										Oil and Gas Exploration and Production								Midstream
(millions)	Consolidated			United States		Eastern Mediter- ranean		West Africa		Other Int'l		United States			Intersegment Eliminations and Other ⁽¹⁾			Corporate		Consolidated		United States		Eastern Mediter- ranean		West Africa		Other Int'l		United States		Intersegment Eliminations and Other⁽¹⁾			Corporate
Three Months Ended June 30, 2018
Three Months Ended September 30, 2018																				Three Months Ended September 30, 2018
Crude Oil Sales	$	749		$	635	$	2	$	112	$	—	$	—		$	—		$	—	$	744	$	655	$	2	$	87	$	—	$	—	$	—		$	—
NGL Sales	137			137		—		—		—		—			—			—		166		166		—		—		—		—		—			—
Natural Gas Sales	214			98		111		5		—		—			—			—		226		98		122		6		—		—		—			—
Total Crude Oil, NGL and Natural Gas Sales	1,100			870		113		117		—		—			—			—		1,136		919		124		93		—		—		—			—
Sales of Purchased Oil and Gas																				72		26		—		—		—		46		—			—
Income from Equity Method Investees and Other	64			—		—		36		—		28			—			—		65		—		—		34		—		31		—			—
Sales of Purchased Oil and Gas	66			24		—		—		—		42			—			—
Intersegment Revenues	—			—		—		—		—		85			(85		)	—		—		—		—		—		—		91		(91		)	—
Total Revenues	1,230			894		113		153		—		155			(85		)	—		1,273		945		124		127		—		168		(91		)	—
Lease Operating Expense	132			114		5		19		—		—			(6		)	—		124		114		7		15		—		—		(12		)	—
Production and Ad Valorem Taxes	50			48		—		—		—		2			—			—		47		46		—		—		—		1		—			—
Gathering, Transportation and Processing Expense	100			133		—		—		—		22			(55		)	—		97		129		—		—		—		28		(60		)	—
Other Royalty Expense	10			10		—		—		—		—			—			—		5		5		—		—		—		—		—			—
Total Production Expense	292			305		5		19		—		24			(61		)	—		273		294		7		15		—		29		(72		)	—
DD&A	465			394		15		26		—		22			(4		)	12
Loss (Gain) on Divestitures	(78		)	21		10		—		—		(109		)	—			—



Asset Impairments	168			168			—		—			—			—		—			—
Purchased Oil and Gas	128			67			—		—			—			61		—			—
Loss on Commodity Derivative Instruments	328			260			—		68			—			—		—			—
Income (Loss) Before Income Taxes	553			(127		)	535		112			(27		)	428		(40		)	(328		)

Six Months Ended June 30, 2017
Crude Oil Sales	$	1,084		$	897		$	2	$	185		$	—		$	—	$	—		$	—
NGL Sales	213			213			—		—			—			—		—			—
Natural Gas Sales	714			440			263		11			—			—		—			—
Total Crude Oil, NGL and Natural Gas Sales	2,011			1,550			265		196			—			—		—			—
Income from Equity Method Investees and Other	84			—			—		52			—			32		—			—
Intersegment Revenues	—			—			—		—			—			127		(127		)	—
Total Revenues	2,095			1,550			265		248			—			159		(127		)	—
Lease Operating Expense	263			211			14		40			—			—		(2		)	—
Production and Ad Valorem Taxes	73			72			—		—			—			1		—			—
Gathering, Transportation and Processing Expense	240			280			—		—			—			32		(72		)	—
Other Royalty Expense	10			10			—		—			—			—		—			—
Total Production Expense	586			573			14		40			—			33		(74		)	—
DD&A	1,031			886			37		74			2			10		—			22
Loss on Marcellus Shale Upstream Divestiture	2,322			2,322			—		—			—			—		—			—
Gain on Commodity Derivative Instruments	(167		)	(154		)	—		(13		)	—			—		—			—
Income (Loss) Before Income Taxes	(2,275		)	(2,251		)	207		138			(11		)	107		(35		)	(430		)

June 30, 2018
Goodwill ⁽²⁾	$	1,402		$	1,291		$	—	$	—		$	—		$	111	$	—		$	—
Total Assets	21,854			15,138			2,996		1,275			62			2,280		(140		)	243
December 31, 2017
Goodwill ⁽²⁾	1,310			1,310			—		—			—			—		—			—
Total Assets	21,476			15,767			2,846		1,308			114			1,357		(163		)	247


⁽¹⁾	The intersegment eliminations related to income (loss) before income taxes are the result of midstream expenditures. These costs are presented as property, plant and equipment within the E&P business on an unconsolidated basis, in accordance with the successful efforts method of accounting, and are eliminated upon consolidation.