UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
ý☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 20182019
or
o☐ 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 | | 73-0785597 |
| (State of incorporation) | | (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)
|
(281) 872-3100
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
|
| | | | |
| Securities registered pursuant to Section 12(b) of the Act: |
| Title of each class | | Trading Symbol(s) | | Name of each exchange on which registered |
| Common Stock, $0.01 par value | | New YorkNBL | | The Nasdaq Stock ExchangeMarket LLC |
| | | | (NASDAQ Global Select Market) |
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. ý☒ Yes oYes☐ 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. o☐ Yes ý☒ 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. ý☒ Yes oYes☐ No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). ý☒ Yes oYes☐ 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. ý
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one): |
| | | | | | | |
Large accelerated filerx | ☒
| Accelerated filer o☐ | Non-accelerated filer o☐ | Smaller reporting companyo | ☐ | Emerging growth companyo | ☐ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).o☐ Yes ý☒ No
Aggregate market value of Common Stock held by nonaffiliates as of June 30, 2018: $17.02019: $10.7 billion.
Number of shares of Common Stock outstanding as of December 31, 2018: 477,643,425.2019: 478,509,368.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive proxy statement for the 20192020 Annual Meeting of Shareholders to be held on April 23, 2019,28, 2020, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2018,2019, are incorporated by reference into Part III.
TABLE OF CONTENTS
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| | |
| PART I |
| Items 1. and 2. | | |
| Item 1A. | | |
| Item 1B. | | |
| Item 3. | | |
| Item 4. | | |
| PART II |
| Item 5. | | |
| Item 6. | | |
| Item 7. | | |
| Item 7A. | | |
| Item 8. | | |
| Item 9. | | |
| Item 9A. | | |
| Item 9B. | | |
| PART III |
| Item 10. | | |
| Item 11. | | |
| Item 12. | | |
| Item 13. | | |
| Item 14. | | |
| PART IV |
| Item 15. | | |
| Item 16. | | |
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;strategies, including our capital spending plans;
our future results of operations;
our liquidity and ability to finance our exploration and development activities;
our ability to successfully and economically explore for and develop crude oil, natural gas liquids (NGLs) and natural gas resources;
anticipated trends in our business;
market conditions in the oil and gas industry;
the impact of governmental regulation, including United States (US) federal, state, local, and foreign host government tax regulations, fiscal policies and terms, as well as that involving the protection of the environment or marketing of production and other regulations;
our ability to make and integrate acquisitions or execute divestitures; 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.
PART I
Items 1. and 2. Business and Properties
In this report, unless otherwise indicated or where the context otherwise requires, information includes that of Noble Energy, Inc. and its subsidiaries (Noble Energy, the Company, we or us). All references to production, sales volumes and reserves quantities are net to our interest unless otherwise indicated. For a summary of commonly used industry terms and abbreviations used in this report, see the Glossary, located at the end of this report. Noble Energy (NYSE:(Nasdaq: NBL) is an independent crude oil and natural gas exploration and production company committed to meeting the world’s growing energy needs and delivering competitive returns to its shareholders. Founded in 1932 and incorporated in Delaware in 1969, Noble Energy is guided by itsour values, its commitment to safety, and respect for stakeholders, communities and the environment. For more information on how the Company fulfills its purpose: Energizing the World, Bettering People's Lives®, visit https://www.nblenergy.com. Information on our website is not incorporated by reference into, and does not constitute a part of, this report.
Portfolio Our portfolio of assets is diversified through US and international projects and production mix among crude oil, NGLs and natural gas. In particular, our business is focused on both US onshore unconventional basins and certain global offshore conventional basins in the Eastern Mediterranean and off the west coast of Africa. In US onshore unconventional basins, we have demonstrated our ability to apply geological, drilling, completion, and midstream design and operational expertise. In US onshore, we utilizeexpertise through an Integrated Development Plan (IDP) approach, which applies a major project development approachis designed to an unconventional basin.optimize capital efficiency and drive returns. In the global offshore, we have hadour notable exploration and major project successes which have led to sanction (meaning final investment decision has been reached) of multiple major development projects and have provided long-lived cash flows to our business.
Capital Program Looking ahead, approximately 70% In addition, our midstream business and equity method investments represent essential components of our 2019 capital program (excluding capital funded by Noble Midstream Partnersbusiness as well as necessary and acquisition capital related to the EMG Pipeline) is allocated to US onshore development, primarily focused on liquids-rich opportunities in the Delaware Basin, Denver-Julesburg (DJ) Basin, and Eagle Ford Shale. Eastern Mediterranean capital expenditures, including remaining costs associated with the Leviathan project, represent approximately 20%integral elements of the total. The remaining portion of the capital program is designated for the drilling of a crude oil development well in West Africa, and other exploration and corporate activities. See our value chain.Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Operating Outlook – 2019 Capital Investment Program.
Reportable Segments We manage our operations by geographic region and the nature of the products and services we offer. We have the following reportable segments: United States, Eastern Mediterranean, West Africa, Other International and Midstream. The geographical reportable segments are in the business of crude oil and natural gas acquisition, and exploration, development, and production (Oil and Gas Exploration and Production). The Midstream reportable segment consists primarily of our interest in Noble Midstream Partners LP (Noble Midstream Partners, Nasdaq: NBLX), which we consolidate. Noble Midstream Partners develops, owns, and operates domestic midstream infrastructure assets, as well as invests in other financially attractive
Divestiture and Acquisition ActivitiesWe maintain an active portfolio management program which includes divestitures of assets through asset or equity sales, exchanges or other transactions. Our portfolio transformation executed over the past few years has included divestitures of Gulf of Mexico assets, a 7.5% working interest in Tamar, our 50% interest in CONE Gathering LLC, our investment in CNX Midstream Partners common units, and other non-core US onshore assets. As a result, our divestitures generated cash proceeds of $2.0 billion and $2.1 billion in 2018 and 2017, respectively, which were used to improve our capital structure, fund a portion of our capital program, strengthen our liquidity and return value to shareholders through the share repurchase program. We expect active portfolio management to continue as an element in our strategic program.
Oil and Gas Properties and Activities We search for crude oil and natural gas properties onshore and offshore and seek to acquire exploration rights and conduct exploration activities in areas of interest. Our activities include geophysical and geological evaluation;evaluation, analysis of commercial, regulatory and political risks;risks, and exploratory and development drilling leading to production, where appropriate.
Our current portfolio consists primarily of interests in developed and undeveloped crude oil and natural gas leases and concessions. These properties contribute all of our crude oil, NGL and natural gas production, provide additional investment opportunities in proved areas, and offer further exploration opportunities. Our new venture areas provide frontier and established basin exploration opportunities, which may result in the establishment of new operational areas in the future. We also own or invest in midstream assets primarily used in the gathering, processing and transportation of our US onshore production. See Midstream – Properties and Activities.
The map below illustrates the locations of our significant crude oil and natural gas exploration and production activities:
Development Activities Our development projects have resulted from both exploration success, as well as periodic leasing activities, which provide entrance to low cost assets. Theseand periodic strategic acquisitions. We believe these projects provide opportunities for growth at attractive financial returns. Each project progresses, as appropriate, through the various development phases including appraisal, engineering and design, development drilling, construction and production. While development projects require significant capital investments, typically over a multi-year period, they are expected to offer sustained cash flows during production.
In US onshore, our low production-risk development programs are centered around IDPs and generate efficiencies for upstream and midstream development. IDPs are generally areas of highly contiguous acreage, typically held by production, that accommodate drilling long lateral wells and other operational synergies. The approach also benefits from the ability to accommodatedeploy a flexible capital investment program that can be varied in response to changes in the commodity price environment. We continue to enhance project performance in these areas through design, technology and operational efficiencies.
Offshore, we engage in long-cycle development projects, such as progressing development at the Leviathan natural gas field, offshore Israel, which commenced production at the largest natural gas discovery in our history, and advancing Aseng crude oil development andend of December 2019, as well as the Alen natural gas monetizationGas Monetization project in West Africa. Our development activities are discussed in more detail in the sections below.
Exploration Activities We primarily focus on organic growth from exploration and development drilling activities, concentrating on existing basins or plays where we believe we have strategic competitive advantages or in new basins with attractive geological potential and the opportunity for competitive project financial returns. These advantages are derived from proprietary seismic data and operational expertise, which we believe will generate superior returns over the oil and gas business cycle. We have had substantial historic exploration success in the Levant Basin offshore Eastern Mediterranean and the Douala Basin offshore West Africa, resulting in the successful completion of numerous major development projects. In 2018,2019, we conducted limited exploration activities as we focused our capital expendituresinvestment program on the development of US onshore assets and progressing the Leviathan field and US onshore assets.
Goodwill Impairment During fourth quarter 2018, primarily resulting from the dropdevelopment project to first production in West Texas Intermediate index (WTI) strip pricing at the end of 2018, we determined that goodwill of $1.3 billion, which had arisen from the Clayton Williams Energy Acquisition, had been fully impaired. We recorded a charge of $1.3 billion. See Item 8. Financial Statements and Supplementary Data – Note 6. Goodwill Impairment.December 2019.
Proved Reserves Disclosures
Proved Oil and Gas Reserves Proved reserves at December 31, 20182019 were as follows: | | | | | Crude Oil and Condensate | | NGLs | | Natural Gas | | Total | | Crude Oil & Condensate | | NGLs | | Natural Gas | | Total |
| Reserves Category | | (MMBbls) | | (MMBbls) | | (Bcf) | | (MMBoe)(1) | | (Percent) | |
| | | | (MMBbls) | | (MMBbls) | | (Bcf) | | (MMBoe)(1) | | (Percent) |
| Proved Developed | | | | | | | | | | | | | | | | | | | | |
| United States | | 165 |
| | 121 |
| | 929 |
| | 442 |
| | 59 | % | | 176 |
| | 138 |
| | 1,055 |
| | 490 |
| | 33 | % |
| Israel | | 2 |
| | — |
| | 1,295 |
| | 218 |
| | 29 | % | | 9 |
| | — |
| | 5,463 |
| | 920 |
| | 61 | % |
| Equatorial Guinea | | 26 |
| | 9 |
| | 355 |
| | 94 |
| | 12 | % | | 25 |
| | 10 |
| | 355 |
| | 94 |
| | 6 | % |
| Total Proved Developed Reserves | | 193 |
| | 130 |
| | 2,579 |
| | 754 |
| | 100 | % | | 210 |
| | 148 |
| | 6,873 |
| | 1,504 |
| | 100 | % |
| Proved Undeveloped | | |
| | | | |
| | |
| | | | |
| | | | |
| | |
| | |
| United States | | 255 |
| | 136 |
| | 1,015 |
| | 560 |
| | 48 | % | | 201 |
| | 125 |
| | 964 |
| | 486 |
| | 89 | % |
| Israel | | 6 |
| | — |
| | 3,635 |
| | 612 |
| | 52 | % | | — |
| | — |
| | 132 |
| | 22 |
| | 4 | % |
| Equatorial Guinea | | 3 |
| | — |
| | 2 |
| | 3 |
| | — | % | | 2 |
| | 5 |
| | 182 |
| | 38 |
| | 7 | % |
| Total Proved Undeveloped Reserves | | 264 |
| | 136 |
| | 4,652 |
| | 1,175 |
| | 100 | % | | 203 |
| | 130 |
| | 1,278 |
| | 546 |
| | 100 | % |
| Total Proved Reserves | | 457 |
| | 266 |
| | 7,231 |
| | 1,929 |
| | | | 413 |
| | 278 |
| | 8,151 |
| | 2,050 |
| | |
| |
(1) | Million barrels oil equivalent. Natural gas is converted on the basis of six Mcf of gas per one barrel of crude oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given commodity price disparities, the price for a barrel of crude oil equivalent for US natural gas and NGLs is significantly less than the price for a barrel of crude oil. In Israel, we sell natural gas under contracts where the majority of the price is fixed, resulting in less commodity price disparity. |
(1) Million barrels oil equivalent. Natural gas is converted on the basis of six Mcf of gas per one barrel of crude oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given commodity price disparities, the price for a barrel of crude oil equivalent for US natural gas and NGLs is significantly less than the price for a barrel of crude oil. In Israel, we sell natural gas under contracts where the majority of the price is fixed, resulting in less commodity price disparity.
Our proved reserves totaled 1,929 MMBoe as of December 31, 2018 as compared with 1,965 MMBoe as of December 31, 2017. Our proved reserves are 48% US onshore and 52% US and 48% international, and theinternational. The commodity mix is 37% global34% liquids (crude oil and NGLs), 46%50% international natural gas and 17%16% US natural gas.
We have historically added reserves through our exploration program, development activities, and acquisition of producing properties. Changes in proved reserves were as follows: |
| | | | | | | | | |
| | | Year Ended December 31, |
| (MMBoe) | | 2018 | | 2017 | | 2016 |
| Proved Reserves Beginning of Year | | 1,965 |
| | 1,437 |
| | 1,421 |
|
| Revisions of Previous Estimates | | (2 | ) | | 135 |
| | 64 |
|
| Extensions, Discoveries and Other Additions | | 223 |
| | 736 |
| | 179 |
|
| Purchase of Minerals in Place | | — |
| | 57 |
| | 4 |
|
| Sale of Minerals in Place | | (128 | ) | | (261 | ) | | (77 | ) |
| Production | | (129 | ) | | (139 | ) | | (154 | ) |
| Proved Reserves End of Year | | 1,929 |
| | 1,965 |
| | 1,437 |
|
|
| | | | | | | | | |
| | | Year Ended December 31, |
| (MMBoe) | | 2019 |
| 2018 |
| 2017 |
| Proved Reserves, Beginning of Year | | 1,929 |
| | 1,965 |
| | 1,437 |
|
Revisions of Previous Estimates(1) | | (50 | ) | | (2 | ) | | 135 |
|
| Extensions, Discoveries and Other Additions | | 305 |
| | 223 |
| | 736 |
|
| Purchase of Minerals in Place | | — |
| | — |
| | 57 |
|
| Sale of Minerals in Place | | (2 | ) | | (128 | ) | | (261 | ) |
| Production | | (132 | ) | | (129 | ) | | (139 | ) |
| Proved Reserves, End of Year | | 2,050 |
| | 1,929 |
| | 1,965 |
|
| |
(1) | Includes negative price revisions of 53 MMBoe in 2019 and positive price revisions of 27 MMBoe and 30 MMBoe in 2018 and 2017, respectively. |
Proved Undeveloped Reserves (PUDs) As of December 31, 2018, ourChanges in PUDs, totaled 1,175 MMBoe, or 61%which total 27% of proved reserves. Changes in PUDsreserves, were as follows for the year ended December 31, 2018.2019: | | | (MMBoe) | | United States | | Israel | | Equatorial Guinea | | Total | | United States | | Israel (1) | | Equatorial Guinea | | Total |
| Proved Undeveloped Reserves, Beginning of Year | | 482 |
| | 615 |
| | — |
| | 1,097 |
| | 560 |
| | 612 |
| | 3 |
| | 1,175 |
|
| Revisions of Previous Estimates | | (23 | ) | | — |
| | — |
| | (23 | ) | | (67 | ) | | (39 | ) | | 4 |
| | (102 | ) |
| Extensions, Discoveries and Other Additions | | 181 |
| | 12 |
| | 3 |
| | 196 |
| | 167 |
| | — |
| | 34 |
| | 201 |
|
| Sale of Minerals in Place | | — |
| | (15 | ) | | — |
| | (15 | ) | |
| Conversion to Proved Developed | | (80 | ) | | — |
| | — |
| | (80 | ) | | (174 | ) | | (551 | ) | | (3 | ) | | (728 | ) |
| Proved Undeveloped Reserves, End of Year | | 560 |
| | 612 |
| | 3 |
| | 1,175 |
| | 486 |
| | 22 |
| | 38 |
| | 546 |
|
| | | | | | | | | | |
| Conversion Percentage (Percent of Beginning Balance) | | | 31 | % | | 90 | % | | 100 | % | | 61 | % |
| |
(1) | In Israel, PUDs revisions of previous estimates reflects a reclassification to developed reserves associated with our Tamar field based upon our determination the reserves are accessible with limited further development. As such, we concurrently reflect an upward |
revision within proved developed reserves. Conversions to proved developed reserves relate to commencement of Leviathan production in December 2019.
Revisions of Previous PUD EstimatesRevisions of previous PUD revisions included:
| |
• | Price Revisions US onshorepositive price revisions (price impact to opening balance) of 3 MMBoe weredue to changes in 12-month average commodity prices.
|
| |
• | Non-Price RevisionsPositive price revisions were offset by negative non-price revisions of 26 MMBoe, including the following:
|
| |
• | the DJ Basin included a positive 8 MMBoe non-price revision, which included a positive revision of approximately 24 MMBoe associated with the adoption of Accounting Standards Codification (ASC) 606, Revenues from Contracts with Customers (ASC 606), partially offset by a negative revision of 16 MMBoe due to removal of PUDs locations due to changes in the previously adopted development plan;
|
estimates were as follows for the
Delaware Basin included a negative 25 MMBoe non-price revision primarily due to changes in expected recoveries and higher operating and capital costs; andyear ended December 31, 2019: the Eagle Ford Shale included a negative 9 MMBoe non-price revision primarily due to removal of PUDs locations due to changes in the previously adopted development plan. |
| | | | | | | | | | | | | | | |
| (MMBoe) | | DJ Basin | | Delaware Basin | | Israel | | Equatorial Guinea | | Total |
| Price | | (2 | ) | | (15 | ) | | — |
| | 3 |
| | (14 | ) |
| Development Plans | | (19 | ) | | (25 | ) | | (39 | ) | | 1 |
| | (82 | ) |
| Performance | | — |
| | (6 | ) | | — |
| | — |
| | (6 | ) |
| Total | | (21 | ) | | (46 | ) | | (39 | ) | | 4 |
| | (102 | ) |
Extensions, Discoveries and Other AdditionsExtensions of proved reserves were primarily due to drilling plans for new wells, of which 94 MMBoe, 69 MMBoe, 18 MMBoe, 12 MMBoe and 3 MMBoe werePUD additions in US onshore are primarily located in the DJ Basin, Delaware Basin, Eagle Ford Shale, Tamar field andresulting from the inclusion of new wells within drilling plans. Equatorial Guinea respectively.additions relate to the April 2019 sanction of the Alen Gas Monetization project, for which first sales are expected in the first half of 2021.
US PUDs Locations During the year, we converted 80 MMBoe of our US PUDs, or 17% of our US PUDs beginning balance,Conversion to developed status. The majority of these conversions were in the DJ Basin and Delaware Basin. PUDs conversions were less than 20% in 2018 as we allocated a portion of capital to convert unproved reserves for acreage delineation and lease retention, primarily in the Delaware Basin. In 2018, capital spent to convert approximately 25 MMBoe of unproved reserves to proved developed was approximately $355 million. Based on our current inventory of identified horizontal well locations and our anticipated rate of drilling and completion activity, we expect our US PUDs recorded as of December 31, 2018 to be converted to proved developed reserves within five years of initial recognition.
Our PUDs are expected to be recovered from new wells on undrilled acreage or from existing wells where additional capital expenditures are required for completion, such as drilled but uncompleted (DUC) wells. As of December 31, 2018, 99 MMBoe of PUDs were associated with US onshore DUC well locations, with 42%, 33% and 25% of locations in the DJ Basin, Delaware Basin and Eagle Ford Shale, respectively.
International PUDs LocationsProved Developed PUDs in the Tamar field decreased 15 MMBoe due to the first quarter 2018 sale of a 7.5% working interest. The PUDs in our Tamar Southwest field represent less than 5% of our international PUDs. These PUDs are expected to remain undeveloped for five years or longer since initial disclosure in 2013. We have been working with the government of Israel for final approval of the development plan, which we received in January 2019, and have progressed capital investment within this field, including laying subsea equipment for future tie-in of field production into existing Tamar infrastructure. Other than the Tamar Southwest PUDs, we expect all of our international PUDs, including the 551 MMBoe associated with the initial phase of development of the Leviathan field, to be converted to proved developed reserves within five years of initial recognition.
Development CostsCosts incurredto convert PUDs to proved developed reserves were approximately $1.0 billion in 2018, $1.2 billion in 2017, and $656 million in 2016. Costs incurred in 2018 primarily related to the DJ Basin and Delaware Basin development projects. In addition, we incurred approximately $646 million and $416 million in 2018 and 2017, respectively, to advance the development of the Leviathan PUDs, which are expected to be converted to proved developed reserves with project start up by the end of 2019.
Estimated future development costs relating to the development of all PUDs are projected to be approximately $2.1 billion in 2019, $1.5 billion in 2020, and $1.1 billion in 2021. Estimated future development costs include capital spending on development projects and PUDs related to development projects will be reclassified to proved developed reserves when production commences.
Drilling Plans Our long-range development plans will result in the conversion of all PUDs to developed reserves within five years of their initial recognition, with the exception of the previously mentioned Tamar Southwest PUDs. PUDs, associated with theoffshore Israel. Tamar Southwest PUDs are approximately 4% of total PUDs and have remained undeveloped since initial disclosure in 2013. In 2019, we received final approval of the development plan from the government of Israel and progressed capital investment in the field, including laying subsea equipment for future tie-in of field production into existing Tamar infrastructure. Our development plan includes additional capital investment in 2020 and conversion of Tamar Southwest PUDs to proved developed reserves in 2023, which we currently believe will align start-up with local and regional natural gas demand.
PUDs are expected to be converted to proved developed reserves prior to the end of 2020 as contemplated in our long-range development plan. Initial productionrecovered from all PUDs is expected to begin during the years 2019 to 2023.
In accordance with US GAAP, we disclose a standardized measure of discounted future net cash flows related to our proved reserves. In order to standardize the measure, all companiesnew wells on undrilled acreage or from existing wells where additional capital expenditures are required, to use a 10% discount rate and Securities and Exchange Commission (SEC) pricing rules. This prescribed calculation can result in some PUDs having negative present worth, meaning while these PUDs have positive cash flows, the rate of return is lower than 10%.such as from drilled but uncompleted (DUC) wells. As of December 31, 2018,2019, less than 10% of our PUDs were associated with US onshore DUC well locations. Our development plan contemplates production to commence from these wells in 2020.
When preparing development plans and estimates of PUDs, we had no PUDs with a negative present worth when discounted at 10%.
Development CostsCosts incurred to develop our PUDs in 2019 totaled $1.5 billion. Of this amount, $1.1 billion, $399 million and $48 million related to the conversion of year end 2018 PUDs to proved developed reserves in US onshore, the Leviathan field offshore Israel and the Aseng crude oil well in Equatorial Guinea, respectively.
In addition, we spent $131 million to convert unproved reserves to proved developed reserves in US onshore and $24 million progressing PUDs that have not yet been converted to proved developed reserves.
Future Development CostsFuture development costs include amounts we expect to spend converting PUDs to proved developed reserves. Estimated future development costs for PUDs as of December 31, 2019, are as follows: |
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| (millions) | | 2020 | | 2021 | | 2022 |
| Future Development Costs | | $ | 1,191 |
| | $ | 920 |
| | $ | 994 |
|
Estimated future development costs include capital spending on development projects. PUDs related to these projects will be reclassified to proved developed reserves when production commences.
Internal Controls Over Reserves Estimates Our policies and processes regarding internal controls over the recording of reserves estimates require reserves to be in compliance with SEC definitions and guidance and prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our internal controls over reserves estimates also include the following:
the Audit Committee of our Board of Directors reviews significant reserves changes on an annual basis;
fields that meet a minimum reserve quantity threshold, which combined represent over 80% of our proved reserves, are audited by Netherland, Sewell & Associates, Inc. (NSAI), a third-party petroleum consulting firm, on an annual basis;
and
NSAI is engaged by, and has direct access to, the Audit Committee.
See Third-Party Reserves Audit, below.
Responsibility for compliance in reserves estimation is delegated to our Corporate Reservoir Engineering group. Qualified petroleum engineers in our Houston and Denver offices prepare all reserves estimates for our geographical regions. These reserves estimates are reviewed and approved by management and senior engineering staff with final approval by the Senior Vice President – Corporate Development and certain other members of senior management.
Our Senior Vice President – Corporate Development oversees our corporate business development, strategic planningexploration and reserves departments. He is the technical person primarily responsible for overseeing the preparation of our reserves estimates and the third-party audit of our reserves estimates. He has Bachelor of Science and Master of Science degrees in Petroleum Engineering and over 3839 years of industry experience. Since 2008,2006, he has worked with positions of increasing responsibility in engineering, evaluations and business unit management at the Company. The Senior Vice President – Corporate Development reports directly to our Chief Executive Officer.
Technologies Used in Reserves Estimation The SEC’s reserves rules allow the use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
We used a combination of production and pressure performance, wireline wellbore measurements, simulation studies, offset analogies, seismic data and interpretation, wireline formation tests, geophysical logs and core data to calculate our reserves estimates.
Based on reasonable certainty of reservoir continuity in US onshore formations where we operate, we may record proved reserves associated with wells more than one offset location away from an existing proved producing well. All of our wells drilled that were more than one offset away from a proved producing well at the time of drilling were determined to be economically producible.
Third-Party Reserves Audit In each of the years 2019, 2018, and 2017, and 2016, weour Audit Committee retained NSAI to perform audits of proved reserves. The reserves audit for 20182019 included a detailed review of sixseven of our major US onshore and international fields, which covered approximately 98%99% of total proved reserves.
In connection with the 20182019 reserves audit, NSAI prepared its own estimates of our proved reserves and compared its estimates to those prepared by us. 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, 2018,2019, 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, which should be read in its entirety, is attached as Exhibit 99.1 to this Annual Report on Form 10-K.
Sales Volumes, Price and Cost Data SalesThe table below includes sales volumes, price and cost data for each geographical area and field that contained 15% or more of total proved reserves as of December 31, 2019. Total proved reserves for the Leviathan field accounted for over 15% of total proved reserves as of December 31, 2019. While the Leviathan field commenced production in December 2019, natural gas sales from that field in 2019 were as follows:immaterial; thus, the Leviathan field is not presented in the table below.
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Sales Volumes (1) | | Average Sales Price (1)(2) | | Production Cost (3) |
| | | Crude Oil & Condensate | | NGLs | | Natural Gas | | Crude Oil & Condensate | | NGLs | | Natural Gas | | Total |
| | | (MBbl) | | (MBbl) | | (MMcf) | | (Per Bbl) | | (Per Bbl) | | (Per Mcf) | | (Per BOE) |
| Year Ended December 31, 2018 | | | | | | | | | | | | |
United States (4) | | | | |
| | | | | | | | | | |
| DJ Basin | | 23,165 |
| | 8,880 |
| | 83,766 |
| | $ | 63.06 |
| | $ | 25.32 |
| | $ | 2.13 |
| | $ | 4.53 |
|
| Other US | | 18,506 |
| | 13,761 |
| | 88,370 |
| | 58.69 |
| | 26.24 |
| | 2.90 |
| | 6.16 |
|
| Total US | | 41,671 |
| | 22,641 |
| | 172,136 |
| | $ | 61.12 |
| | $ | 25.88 |
| | $ | 2.53 |
| | $ | 5.35 |
|
Israel (5) | | 113 |
| | — |
| | 86,461 |
| | $ | 63.25 |
| | $ | — |
| | $ | 5.47 |
| | $ | 2.30 |
|
Equatorial Guinea (6) | | 5,690 |
| | — |
| | 77,767 |
| | 68.53 |
| | — |
| | 0.27 |
| | 5.21 |
|
| Total Consolidated Operations | | 47,474 |
| | 22,641 |
| | 336,364 |
| | $ | 62.01 |
| | $ | 25.88 |
| | $ | 2.76 |
| | $ | 4.78 |
|
Equity Investee (7) | | 576 |
| | 1,962 |
| | — |
| | 68.99 |
| | 42.14 |
| | — |
| | — |
|
| Total | | 48,050 |
| | 24,603 |
| | 336,364 |
| | $ | 62.10 |
| | $ | 27.18 |
| | $ | 2.76 |
| | — |
|
| Year Ended December 31, 2017 | | | | | | | | | | | | |
United States (4) | | | | |
| | | | | | | | | | |
| DJ Basin | | 21,564 |
| | 6,911 |
| | 70,660 |
| | $ | 50.20 |
| | $ | 25.22 |
| | $ | 2.96 |
| | $ | 4.46 |
|
| Marcellus Shale | | 233 |
| | 1,654 |
| | 63,443 |
| | 36.91 |
| | 23.81 |
| | 3.15 |
| | 1.05 |
|
| Other US | | 18,757 |
| | 12,521 |
| | 87,364 |
| | 48.01 |
| | 22.34 |
| | 2.99 |
| | 6.48 |
|
| Total US | | 40,554 |
| | 21,086 |
| | 221,467 |
| | $ | 49.11 |
| | $ | 23.40 |
| | $ | 3.02 |
| | $ | 4.81 |
|
| Israel | | | | | | | | | | | | | | |
| Tamar Field | | 130 |
| | — |
| | 96,894 |
| | $ | 46.95 |
| | $ | — |
| | $ | 5.37 |
| | $ | 2.02 |
|
| Other Israel | | — |
| | — |
| | 2,346 |
| | — |
| | — |
| | 3.56 |
| | — |
|
| Total Israel | | 130 |
| | — |
| | 99,240 |
| | $ | 46.95 |
| | $ | — |
| | $ | 5.32 |
| | $ | 2.01 |
|
Equatorial Guinea (6) | | 6,460 |
| | — |
| | 87,269 |
| | 53.68 |
| | — |
| | 0.27 |
| | 4.30 |
|
| Total Consolidated Operations | | 47,144 |
| | 21,086 |
| | 407,976 |
| | $ | 49.73 |
| | $ | 23.40 |
| | $ | 3.01 |
| | $ | 4.31 |
|
Equity Investee (7) | | 662 |
| | 2,162 |
| | — |
| | 55.13 |
| | 38.48 |
| | — |
| | — |
|
| Total | | 47,806 |
| | 23,248 |
| | 407,976 |
| | $ | 49.84 |
| | $ | 24.81 |
| | $ | 3.01 |
| | — |
|
| Year Ended December 31, 2016 | | |
| | | | |
| | |
| | | | |
|
United States (4) | | |
| | |
| | | | |
| | |
| | | | |
|
| DJ Basin | | 20,342 |
| | 7,651 |
| | 82,431 |
| | $ | 40.85 |
| | $ | 14.66 |
| | $ | 2.80 |
| | $ | 3.99 |
|
| Marcellus Shale | | 431 |
| | 3,094 |
| | 177,872 |
| | 28.25 |
| | 16.34 |
| | 1.68 |
| | 0.90 |
|
| Other US | | 15,572 |
| | 9,087 |
| | 62,017 |
| | 38.26 |
| | 14.65 |
| | 2.42 |
| | 6.65 |
|
| Total US | | 36,345 |
| | 19,832 |
| | 322,320 |
| | $ | 39.59 |
| | $ | 14.92 |
| | $ | 2.11 |
| | $ | 3.74 |
|
| Israel | | | | | | | | | | | | | | |
| Tamar Field | | 140 |
| | — |
| | 102,280 |
| | $ | 36.67 |
| | $ | — |
| | $ | 5.22 |
| | $ | 2.58 |
|
| Other Israel | | — |
| | — |
| | 528 |
| | — |
| | — |
| | 3.20 |
| | — |
|
| Total Israel | | 140 |
| | — |
| | 102,808 |
| | $ | 36.67 |
| | $ | — |
| | $ | 5.21 |
| | $ | 2.60 |
|
Equatorial Guinea (6) | | 9,415 |
| | — |
| | 85,987 |
| | 43.54 |
| | — |
| | 0.27 |
| | 4.40 |
|
| Total Consolidated Operations | | 45,900 |
| | 19,832 |
| | 511,115 |
| | $ | 40.39 |
| | $ | 14.92 |
| | $ | 2.42 |
| | $ | 3.72 |
|
Equity Investee (7) | | 629 |
| | 1,993 |
| | — |
| | 45.44 |
| | 26.30 |
| | — |
| | — |
|
| Total | | 46,529 |
| | 21,825 |
| | 511,115 |
| | $ | 40.46 |
| | $ | 15.96 |
| | $ | 2.42 |
| | — |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Sales Volumes | | Average Sales Price (1) | | Average Production Cost (2) |
| | | Crude Oil & Condensate | | NGLs | | Natural Gas | | Crude Oil & Condensate | | NGLs | | Natural Gas | | Total |
| | | (MBbl) | | (MBbl) | | (MMcf) | | (Per Bbl) | | (Per Bbl) | | (Per Mcf) | | (Per BOE) |
| Year Ended December 31, 2019 | | | | | | | | | | | | |
| United States | | | | |
| | | | | | | | | | |
| DJ Basin | | 25,494 |
| | 11,931 |
| | 109,790 |
| | $ | 56.33 |
| | $ | 12.96 |
| | $ | 1.70 |
| | $ | 3.55 |
|
| Other US | | 18,278 |
| | 12,832 |
| | 78,408 |
| | 54.78 |
| | 15.58 |
| | 2.02 |
| | 6.37 |
|
| Total US | | 43,772 |
| | 24,763 |
| | 188,198 |
| | $ | 55.68 |
| | $ | 14.32 |
| | $ | 1.83 |
| | $ | 4.80 |
|
| Israel | | 106 |
| | — |
| | 81,269 |
| | $ | 56.07 |
| | $ | — |
| | $ | 5.55 |
| | $ | 2.73 |
|
| Equatorial Guinea | | 4,792 |
| | — |
| | 67,729 |
| | 61.03 |
| | — |
| | 0.27 |
| | 4.73 |
|
| Total Consolidated Operations | | 48,670 |
| | 24,763 |
| | 337,196 |
| | $ | 56.21 |
| | $ | 14.32 |
| | $ | 2.41 |
| | $ | 4.63 |
|
Equity Investment (3) | | 535 |
| | 1,634 |
| | — |
| | 58.65 |
| | 31.77 |
| | — |
| | — |
|
| Total | | 49,205 |
| | 26,397 |
| | 337,196 |
| | $ | 56.24 |
| | $ | 15.40 |
| | $ | 2.41 |
| | — |
|
| Year Ended December 31, 2018 | | | | | | | | | | | | |
United States (4) | | | | |
| | | | | | | | | | |
| DJ Basin | | 23,165 |
| | 8,880 |
| | 83,766 |
| | $ | 63.06 |
| | $ | 25.32 |
| | $ | 2.13 |
| | $ | 4.53 |
|
| Other US | | 18,506 |
| | 13,761 |
| | 88,370 |
| | 58.69 |
| | 26.24 |
| | 2.90 |
| | 6.16 |
|
| Total US | | 41,671 |
| | 22,641 |
| | 172,136 |
| | $ | 61.12 |
| | $ | 25.88 |
| | $ | 2.53 |
| | $ | 5.35 |
|
| Israel | | 113 |
| | — |
| | 86,461 |
| | $ | 63.25 |
| | $ | — |
| | $ | 5.47 |
| | $ | 2.30 |
|
| Equatorial Guinea | | 5,690 |
| | — |
| | 77,767 |
| | 68.53 |
| | — |
| | 0.27 |
| | 5.21 |
|
| Total Consolidated Operations | | 47,474 |
| | 22,641 |
| | 336,364 |
| | $ | 62.01 |
| | $ | 25.88 |
| | $ | 2.76 |
| | $ | 4.78 |
|
Equity Investment (3) | | 576 |
| | 1,962 |
| | — |
| | 68.99 |
| | 42.14 |
| | — |
| | — |
|
| Total | | 48,050 |
| | 24,603 |
| | 336,364 |
| | $ | 62.10 |
| | $ | 27.18 |
| | $ | 2.76 |
| | — |
|
| Year Ended December 31, 2017 | | |
| | | | |
| | |
| | | | |
|
United States (4) | | |
| | |
| | | | |
| | |
| | | | |
|
| DJ Basin | | 21,564 |
| | 6,911 |
| | 70,660 |
| | $ | 50.20 |
| | $ | 25.22 |
| | $ | 2.96 |
| | $ | 4.46 |
|
| Marcellus Shale | | 233 |
| | 1,654 |
| | 63,443 |
| | 36.91 |
| | 23.81 |
| | 3.15 |
| | 1.05 |
|
| Other US | | 18,757 |
| | 12,521 |
| | 87,364 |
| | 48.01 |
| | 22.34 |
| | 2.99 |
| | 6.48 |
|
| Total US | | 40,554 |
| | 21,086 |
| | 221,467 |
| | $ | 49.11 |
| | $ | 23.40 |
| | $ | 3.02 |
| | $ | 4.81 |
|
| Israel | | | | | | | | | | | | | | |
| Tamar Field | | 130 |
| | — |
| | 96,894 |
| | $ | 46.95 |
| | $ | — |
| | $ | 5.37 |
| | $ | 2.02 |
|
| Other Israel | | — |
| | — |
| | 2,346 |
| | — |
| | — |
| | 3.56 |
| | — |
|
| Total Israel | | 130 |
| | — |
| | 99,240 |
| | $ | 46.95 |
| | $ | — |
| | $ | 5.32 |
| | $ | 2.01 |
|
| Equatorial Guinea | | 6,460 |
| | — |
| | 87,269 |
| | 53.68 |
| | — |
| | 0.27 |
| | 4.30 |
|
| Total Consolidated Operations | | 47,144 |
| | 21,086 |
| | 407,976 |
| | $ | 49.73 |
| | $ | 23.40 |
| | $ | 3.01 |
| | $ | 4.31 |
|
Equity Investment (3) | | 662 |
| | 2,162 |
| | — |
| | 55.13 |
| | 38.48 |
| | — |
| | — |
|
| Total | | 47,806 |
| | 23,248 |
| | 407,976 |
| | $ | 49.84 |
| | $ | 24.81 |
| | $ | 3.01 |
| | — |
|
| |
(3)(2)
| Average production cost includes oil and gas exploration and production operating costs, and workover and repair expense and excludes production and ad valorem taxes, gathering, transportation and processing expense, and other royalty expense. |
| |
(5)
| Sales volume reduction from 2017 is due to the sale of a 7.5% interest in the Tamar field. |
| |
(7)(3)
| Volumes represent sales of condensate and liquefied petroleum gas (LPG) from the LPG plant in Equatorial Guinea. |
At December 31, 2018,2019, our operated properties accounted for substantially all of our total production.sales volumes. 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, 20182019 were as follows: | | | | | Crude Oil Wells | | Natural Gas Wells | | Total | Crude Oil Wells | | Natural Gas Wells | | Total |
| | | Gross | | Net | | Gross | | Net | | Gross | | Net | Gross | | Net | | Gross | | Net | | Gross | | Net |
| United States | | 5,289 |
| | 4,781 |
| | 909 |
| | 842 |
| | 6,198 |
| | 5,623 |
| 4,819 |
| | 4,231 |
| | 807 |
| | 764 |
| | 5,626 |
| | 4,995 |
|
| Israel | | — |
| | — |
| | 7 |
| | 2 |
| | 7 |
| | 2 |
| — |
| | — |
| | 10 |
| | 3 |
| | 10 |
| | 3 |
|
| Equatorial Guinea | | 5 |
| | 2 |
| | 23 |
| | 8 |
| | 28 |
| | 10 |
| 6 |
| | 2 |
| | 23 |
| | 8 |
| | 29 |
| | 10 |
|
| Total | | 5,294 |
| | 4,783 |
| | 939 |
| | 852 |
| | 6,233 |
| | 5,635 |
| 4,825 |
| | 4,233 |
| | 840 |
| | 775 |
| | 5,665 |
| | 5,008 |
|
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 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. Gross crude oil and natural gas wells include 711 wells with multiple completions, meaning completions into more than one productive zone.
Developed and Undeveloped Acreage Developed and undeveloped acreage (including both leases and concessions) in which we held an interest at December 31, 20182019 were as follows:
| | | | | Developed Acreage | | Undeveloped Acreage | Developed Acreage | | Undeveloped Acreage |
| (thousands of acres) | | Gross | | Net | | Gross | | Net | Gross | | Net | | Gross | | Net |
| United States | | | | | | | | | 575 |
| | 453 |
| | 495 |
| | 438 |
|
| Onshore | | 549 |
| | 449 |
| | 527 |
| | 384 |
| |
| Offshore | | 14 |
| | 5 |
| | 6 |
| | 3 |
| |
| Total United States | | 563 |
| | 454 |
| | 533 |
| | 387 |
| |
| International | | |
| | |
| | |
| | |
| |
Israel (1) | | 185 |
| | 74 |
| | 284 |
| | 111 |
| |
| Israel | | 309 |
| | 123 |
| | 161 |
| | 62 |
|
Equatorial Guinea | | 284 |
| | 118 |
| | 81 |
| | 30 |
| 284 |
| | 118 |
| | 26 |
| | 10 |
|
| Newfoundland, Canada | | — |
| | — |
| | 2,332 |
| | 681 |
| — |
| | — |
| | 2,331 |
| | 681 |
|
| Colombia | | — |
| | — |
| | 2,174 |
| | 869 |
|
| Gabon | | — |
| | — |
| | 671 |
| | 403 |
| — |
| | — |
| | 671 |
| | 403 |
|
| Cyprus | | — |
| | — |
| | 95 |
| | 33 |
| — |
| | — |
| | 95 |
| | 33 |
|
| Cameroon | | — |
| | — |
| | 168 |
| | 168 |
| — |
| | — |
| | 168 |
| | 168 |
|
| Total International | | 469 |
| | 192 |
| | 3,631 |
| | 1,426 |
| |
| Total | | 1,032 |
| | 646 |
| | 4,164 |
| | 1,813 |
| 1,168 |
| | 694 |
| | 6,121 |
| | 2,664 |
|
(1) Includes 99,000 gross (47,000 net) undeveloped acres for the Alon D license, which we are in the process of relinquishing.
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.
The
table above
table includes certain undeveloped acreage that is set to expire if production is not established or we take no other action to extend the terms of the leases, licenses or concessions within a specified period of time.
Approximately 91,000, 86,000 and 57,000 net undeveloped acres will expire in 2019, 2020, and 2021, respectively. As of December 31,
2018, approximately 20% of our US onshore undeveloped net acres and 25% of our undeveloped net acres in Israel are set to expire2019, acreage expiring in the next three
years. As of December 31, 2018, there are no PUDs associated with this acreage.years is as follows: |
| | | | | | | | |
| | Net Undeveloped Acreage |
| (thousands of acres) | 2020 | | 2021 | | 2022 |
United States (1) | 29 |
| | 59 |
| | 28 |
|
Israel (2) | 46 |
| | — |
| | — |
|
| Gabon | — |
| | 403 |
| | — |
|
| Total | 75 |
| | 462 |
| | 28 |
|
| |
(1) | Approximately 80% relates to acreage on which we have not recorded PUDs. Of the remaining acreage, there are no PUDs on acreage we plan to let expire as our development plan contemplates the drilling or renewing of leases associated with this acreage prior to expiration. |
| |
(2) | Acreage relates to the Alon D license. |
Drilling Activity The results of crude oil and natural gas wells drilled and completed, for eachregardless of the last three yearswhen drilling was initiated, were as follows: | | | | | Net Exploratory Wells | | Net Development Wells | | | Net Exploratory Wells | | Net Development Wells | | Total |
| | | Productive | | Dry | | Total | | Productive | | Dry | | Total | | Total | Productive | | Dry | | Total | | Productive | | Dry | | Total | |
| Year Ended December 31, 2019 | | | | | | | | | | | | | | |
| United States | | — |
| | — |
| | — |
| | 183.9 |
| | — |
| | 183.9 |
| | 183.9 |
|
| Israel | | — |
| | — |
| | — |
| | 1.6 |
| | — |
| | 1.6 |
| | 1.6 |
|
| Equatorial Guinea | | — |
| | — |
| | — |
| | 0.4 |
| | — |
| | 0.4 |
| | 0.4 |
|
| Total | | — |
| | — |
| | — |
| | 185.9 |
| | — |
| | 185.9 |
| | 185.9 |
|
| Year Ended December 31, 2018 | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | |
| United States | | — |
| | — |
| | — |
| | 203.0 |
| | — |
| | 203.0 |
| | 203.0 |
| — |
| | — |
| | — |
| | 203.0 |
| | — |
| | 203.0 |
| | 203.0 |
|
| Total | | — |
| | — |
| | — |
| | 203.0 |
| | — |
| | 203.0 |
| | 203.0 |
| — |
| | — |
| | — |
| | 203.0 |
| | — |
| | 203.0 |
| | 203.0 |
|
| Year Ended December 31, 2017 | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | |
| United States | | — |
| | — |
| | — |
| | 185.3 |
| | — |
| | 185.3 |
| | 185.3 |
| — |
| | — |
| | — |
| | 185.3 |
| | — |
| | 185.3 |
| | 185.3 |
|
| Israel | | — |
| | — |
| | — |
| | 0.3 |
| | — |
| | 0.3 |
| | 0.3 |
| — |
| | — |
| | — |
| | 0.3 |
| | — |
| | 0.3 |
| | 0.3 |
|
| Suriname | | — |
| | 0.2 |
| | 0.2 |
| | — |
| | — |
| | — |
| | 0.2 |
| — |
| | 0.2 |
| | 0.2 |
| | — |
| | — |
| | — |
| | 0.2 |
|
| Total | | — |
| | 0.2 |
|
| 0.2 |
|
| 185.6 |
|
| — |
|
| 185.6 |
|
| 185.8 |
| — |
| | 0.2 |
|
| 0.2 |
|
| 185.6 |
|
| — |
|
| 185.6 |
|
| 185.8 |
|
| Year Ended December 31, 2016 | | | | | | | | | | | | | | | |
| United States | | 0.4 |
| | 0.5 |
| | 0.9 |
| | 156.7 |
| | — |
| | 156.7 |
| | 157.6 |
| |
| Total | | 0.4 |
| | 0.5 |
| | 0.9 |
| | 156.7 |
| | — |
| | 156.7 |
| | 157.6 |
| |
In addition to the wells drilled and completed in 2018 included in the table above, wells that were in the process of drilling or completing at December 31, 20182019 were as follows:
| | | | | Exploratory(1) | | Development(1) | | Total | Exploratory(1) | | Development(1) | | Total |
| | | Gross | | Net | | Gross | | Net | | Gross | | Net | Gross | | Net | | Gross | | Net | | Gross | | Net |
| United States | | — |
| | — |
| | 114.0 |
| | 107.1 |
| | 114.0 |
| | 107.1 |
| — |
| | — |
| | 72.0 |
| | 64.0 |
| | 72.0 |
| | 64.0 |
|
Israel (2) | | — |
| | — |
| | 4.0 |
| | 1.6 |
| | 4.0 |
| | 1.6 |
| |
| Total | | — |
| | — |
| | 118.0 |
| | 108.7 |
| | 118.0 |
| | 108.7 |
| — |
| | — |
| | 72.0 |
| | 64.0 |
| | 72.0 |
| | 64.0 |
|
| |
(1) | Amounts include wells awaiting completion activities, with the exception of Tamar Southwest as it is not in the process of completing at December 31, 2019. Amounts exclude wells drilled and suspended awaiting a sanctioned development plan or being evaluated to assess the economic viability of the well. |
| |
(2)
| Includes Leviathan 3, 4, 5 and 7 development wells not yet capable of production. Excludes Tamar Southwest well as it is not in the process of drilling or completing at December 31, 2018. |
Oil and Gas Exploration and Production - Properties and Activities
United States
We have been engaged in crude oil, NGL and natural gas exploration and development activities throughout US onshore since 1932. US operations accounted for 74% of 2018 total consolidated sales volumes and 52% of total proved reserves at December 31, 2018. Approximately 42% of the proved reserves in the US are crude oil and condensate, 32% are natural gas and 26% are NGLs. In second quarter 2018, we exited the Gulf of Mexico through sale of our properties.
Oil and Gas Exploration and Production – Properties and Activities
US Onshore
Our US onshore operations are located in proven basins with long-life production profiles.hydrocarbon basins. These assets provide low production-riskgeologic-risk drilling opportunities in liquids-rich areas that offer predictable and long-term production and cash flow growth at attractive financial returns.areas. In addition, we evaluate and consider other US onshore new venture prospects to complement our portfolio. Locations of our US onshore operationslocations as of December 31, 20182019 are shown on the map below:
US onshore operations accounted for 77% of 2019 total consolidated sales volumes and 48% of total proved reserves at December 31, 2019. Approximately 39% of the proved reserves in the US are crude oil and condensate, 34% are natural gas and 27% are NGLs.
Key information for our US onshore operating locations as of, and for the year ended, December 31, 2019, is as follows: |
| | | | | | | | | | | |
| | DJ Basin | | Delaware Basin | | Eagle Ford Shale | | Total |
Net Acreage (thousands) (1) | 336 |
| | 92 |
| | 35 |
| | 463 |
|
| Proved Reserves (MMBoe) | 666 |
| | 204 |
| | 106 |
| | 976 |
|
| Sales Volumes (MBoe/d) | 153 |
| | 66 |
| | 55 |
| | 274 |
|
Gross Wells Drilled (2) | 106 |
| | 66 |
| | 16 |
| | 188 |
|
| Gross Wells Brought Online | 120 |
| | 64 |
| | 25 |
| | 209 |
|
| Gross Non-Operated Wells Participated In | 2 |
| | 21 |
| | — |
| | 23 |
|
| |
(1) | Amounts include net developed and net undeveloped acres. Total excludes approximately 181,000 net acres in the Powder River and Green River Basins and approximately 239,000 net acres in other US onshore locations. |
| |
(2) | The number of wells drilled refers to the number of wells completed, regardless of when drilling was initiated. Amount excludes two refracture wells in the Eagle Ford Shale. |
DJ Basin Our operations in the DJ Basin represent a keythe largest asset within our US onshore asset portfolio. As of December 31, 2018,In 2019, we held approximately 342,000 net acres in the DJ Basin and had proved reserves of 586 MMBoe. Total sales volumes for 2018 were 126 MBoe/d.
2018 Activity In 2018, we focused ourconducted drilling and development activity in all three of our main IDP areas, including Mustang, Wells Ranch, Mustang, and East Pony. Our IDP approach has provided an opportunity to efficiently and economically drive production growth bydevelop our resources through leveraging infrastructure for crude oil, natural gas, and water, including both fresh and produced water assets.infrastructure.
Operationally, our focus on obtaining better results from enhanced completions has led to stronger new well performance. In the Mustang IDP area, our large, contiguous acreage position allows us to focus on row development concepts, which, unlike single-pad development, include sequencing operations across a row to more efficiently develop our acreage.
In the Wells Ranch We are currently using three drilling rigs and Mustang IDP areas, we executed acreage trades which add to our contiguous acreage positions and further allow us to control the pace of development and capital investment. During the year, we completed 99 wells and commenced production on 106 wells. We also participated in approximately two non-operated development wells during 2018. As we continue to manage our portfolio, we executed and closed the sale of certain assets in the Greeley Crescent area in 2018 receiving aggregate proceeds of $68 million. See Item 8. Financial Statements and Supplementary Data – Note 5. Acquisitions and Divestitures.During 2018, we received approval from Colorado regulators of a Comprehensive Drilling Plan (CDP), the first large-scale CDP approved in the State of Colorado. The CDP spans a 100 square mile position over approximately 64,000 net acres in the Mustang IDP area. With primary operatorship over the acreage, we have the opportunity to control the pace of development and to utilize shared facilities and infrastructure, which is expected to reduce trucking and surface access. As part of the CDP, the permitting process has been clarified and the expiration term for a majority of awarded permits is six years, an increase from the previous two years. We have received permits for over 400 locations across the Mustang IDP area.
Delaware Basin (Permian Basin)Our Delaware Basin position was significantly transformed in 2017 with the closing of the Clayton Williams Energy Acquisition, adding 71,000 highly contiguous net acres in the core of the Delaware Basin adjacent to our Reeves County holdings. As of December 31, 2018, we held approximately 108,000 net acres in the Delaware Basin and had proved reserves of 258 MMBoe. Total sales volumes for 2018 were 53 MBoe/d.
2018 Activity In 2018, we continued execution of the Delaware Basin IDP with a focus on lateral length, pad drilling, multi-zone completions and infrastructure development. We transitioned to a row development concept consistent with our strategy in our other US onshore plays. The transition allows for the focusing of development around existing central gathering facilitieshydraulic fracturing crews.
(CGFs)We currently have approximately 385 approved and remaining drilling permits, primarily in our Mustang Comprehensive Drilling Plan (CDP). The vast majority of these permits have six-year terms. In late 2018,addition, in September 2019, we moderatedsubmitted a permitting application for our completion activitysecond large-scale CDP in the basinstate of Colorado. The CDP spans approximately 38,000 net acres in Wells Ranch and allows for up to align250 additional drilling permits. The Wells Ranch CDP acreage is located in an area of higher crude oil production.
Delaware Basin (Permian Basin)In 2019, we continued execution of the Delaware Basin IDP with economica focus on maximizing lateral length, pad drilling, single zone completions, and availableinfrastructure development. We began realizing the benefits of row development, which contributed to reduced well costs and improved cycle times. Newly installed electrical substations have increased reliability of production and reduced costs. We are currently using two rigs and two hydraulic fracturing crews.
We continue to focus on securing our crude oil takeaway capacity.
Duringposition in the year, we completed 70 wells and commenced production on 72 wells. We also participated in approximately 20 non-operated wells during 2018. In addition, we began flowing production to three newly constructed CGFs, an increase from two CGFs in 2017, operated by Noble Midstream Partners.
basin. We utilize the Advantage Pipeline (defined below)System (below), which is 50% owned by Noble Midstream Partners, for a portion of our crude oil takeaway. Additionally, we have supplemented our Delaware Basin takeaway position with a firm sales agreementWe also utilize the EPIC Y-Grade Pipeline (defined below), which brings ourbegan interim crude oil to the Texas Gulf Coast.service in August 2019. The five-year agreement provides for firm gross sales of at least 10 MBbl/d of crude oil beginning in July 2018, which increased to 20 MBbl/d beginning in October 2018 and for the remainder of the agreement. Currently, crude oil sold under the agreement utilizes the buyer's existing firm transport capacity to Corpus Christi, Texas. Once the EPIC Crude Oil Pipeline is fully in service, we will utilize our own firm transport on the EPIC pipeline, discussed below,(below), to deliver volumes to the buyer in Corpus Christi, Texas. We also have a firm sales agreement for gross crude oil volumes of 5 MBbl/d for 2019.
Also during 2018, we dedicatedwhich substantially all of our Delaware Basin acreage position in Reeves County, Texas is dedicated, is scheduled to come online in the first half of 2020. Our crude service will shift to the EPIC Crude Oil Pipeline for firm transport of up to 100 MBbl/d, gross, of crude oil fromonce it comes online, and the Delaware Basin to Corpus Christi, Texas, for a 10-year period beginning at pipeline start-up. EPIC announced that it will provide early access to oil pipeline transportation through its Y-Grade Pipeline in third quarter 2019 while the EPIC Crude Oil Pipeline construction continues with in-service expected in first quarter 2020. This strategic agreement is expected to provide long-term flow assurance for our growing crude oil volumes in this area. With this agreement, we have further diversified our US onshore marketing outlets with access to the Texas Gulf Coast and global markets, at an attractive pipeline transport cost.
As part of the EPIC strategic relationship, in first quarter 2019, we assignedwill commence Y-grade service. Noble Midstream Partners our option to acquire a 30% equity interesthas ownership interests in the EPIC Crude Oil Pipeline, and Noble Midstream Partners subsequently exercised this option with EPIC. Closing of Noble Midstream Partners’ equity interest in the EPIC Crude Oil Pipeline is anticipated in first quarter 2019 and subject to certain conditions precedent. Concurrently, Noble Midstream Partners exercised and closed its option with EPIC to acquire a 15% equity interest in the EPIC Y-Grade pipeline. Cash consideration is expected to total approximately $330 million to $350 million for the interest in the EPIC Crude Oil Pipeline and approximately $165 million to $180 million for the interest in the EPIC Y-Grade Pipeline. Noble Midstream Partners intends to fund the equity investments with its revolving credit facility and/or additional sources of funding.entities that own these pipelines. See Item 8. Financial Statements and Supplementary Data – Note 5. Equity Method Investments5. Acquisitions and Divestitures.Eagle Ford ShaleAs of December 31, 2018,During 2019, we held approximately 35,000 net acres located in Webb and Dimmit counties and had proved reserves of 158 MMBoe. Total sales volumes for 2018 were 69 MBoe/d. Since acquiring these assets, we have continued to apply IDP learnings and enhancements, to optimize development of these assets, including optimizing drilling and completion designs to increase investment efficiency. We have alsoAs we focused on testingcompletion activities, we progressed DUC wells to production and tested co-development of both the Upper and Lower Eagle Ford formation zones.
2018 Activity Our 2018 capital program was primarily focused within the Upper and Lower Eagle Ford formation zones where we completed 20 wells and commenced production on 13 wells. All wells drilled during 2018 were on multi-well pads leveraging centralized infrastructure. In addition, we continued construction of a central delivery facility in the northern area of Gates Ranch which will provide separation and compression capabilities for our multi-well completion program which began in fourth quarter 2018 and will continue into 2019.
Onshore Exploration Activity In 2018, we captured over 100,000 net acres through undeveloped leasehold acquisition activity in the US onshore. In 2019, we expectbegan testing refracturing concepts in the South Gates Ranch area, which could provide opportunities to perform additional geologic studiesre-develop approximately 75 to 100 wells.
US Onshore Exploration ActivityOur US onshore exploration position includes more than 250,000 net acres, with approximately 181,000 net acres in Wyoming in the Powder River and conduct permitting activities.
US Offshore
In second quarter 2018, we closed the sale of our Gulf of Mexico assets, receiving net proceeds of $384 millionGreen River Basins. We continue to progress activities to obtain required approvals and recorded a loss on sale of $24 million. Average annual sales volumes for 2018 were 7 MBoe/d. Proved reserves associated with these properties totaled 23 MMBoe. The divestment enables us to further focus our organization on our highest-return areas that are expected to deliver production and cash flow growth.permits.
International
Our international business focuses on offshore opportunities in a number of countries and diversifies our portfolio. Development projects in the Eastern Mediterranean and West Africa have contributed substantially to our production and cash flow growth over the lastfor more than a decade. Previous exploration successes in these areas have also identified multipleyielded a large inventory of discovered resources which, through major project development, projects that have the potential to contribute to long-term production and cash flow growth in the future.
During 2018,2019, we progressed Phase 1 development of offshore Israel assets primarily through the continued development of Leviathan where first natural gas sales are anticipated by the end offield, which commenced production on December 31, 2019. In addition, we advanced our Eastern Mediterranean regional natural gas export opportunities by executing natural gas sales and purchase agreements (GSPAs) and transportation agreements for the Leviathan and Tamar fields offshore Israel, and continuecontinued efforts to monetize our significant natural gas discoveries offshore West Africa.
Operations in Equatorial Guinea, Cameroon, Gabon, and Cyprus are conducted in accordance with the terms of Production Sharing Contractsproduction sharing contracts (PSCs). Operations in Israel, Newfoundland (Canada), Colombia and other foreign locations are conducted in accordance with concession agreements, permits or licenses. See Item 1A. Risk Factors. Eastern Mediterranean (Israel and Cyprus) One of our operating areas is theThe Eastern Mediterranean, where we have identified the existence of substantial natural gas resources, since we obtainedis one of our first exploration license in 1998.
Israel, our only producing country in our Eastern Mediterranean area, contributed an average of 239 MMcfe/d, net, of naturalcore operating areas. Natural gas sales volumes in 2018, representing approximately 12% of total consolidated sales volumes, primarily from the Tamar field. As of December 31, 2018, we had 830 MMBoe of proved reserves in Israel, which representsfield, represented approximately 43%10% of total proved reserves. Reserves include proved undeveloped reserves associated with the Leviathan field development.consolidated sales volumes during 2019. Our operated offshore Israel leasehold position in the Eastern Mediterranean at December 31, 2018, includedincludes six leases and one license operated offshore Israel. In offshorelicense. Offshore Cyprus, we operate under the terms of a PSC.
At December 31, 2018, the Eastern Mediterranean position included approximately 74,000 net developed acres and 111,000 net undeveloped acres located between 10 and 90 miles offshore Israel in water depths ranging from 700 feet to 6,500 feet. Approximately 47,000 of the 111,000 net undeveloped acres relate to the Alon D license, which we are in the process of relinquishing. The license offshore Cyprus covers approximately 33,000 net undeveloped acresPSC, with acreage adjacent to our offshore Israel acreage.
Locations ofKey information for our operations in the Eastern Mediterranean operating area as of, and for the year ended, December 31, 2019, is as follows: |
| | |
| Total |
Proved Reserves (MMBoe) (1) | 942 |
|
| Sales Volumes (MMcf/d) | 223 |
|
| Net Developed Acres (thousands) | 123 |
|
| Net Undeveloped Acres (thousands) | 95 |
|
Gross Wells Drilled (2) | 4 |
|
| Gross Wells Brought Online | 4 |
|
| |
(1) | Includes 639 MMBoe, 281 MMBoe, and 22 MMBoe related to the Leviathan, Tamar, and Tamar Southwest fields, respectively. |
| |
(2) | The number of wells drilled refers to the number of wells completed, regardless of when drilling was initiated. |
Eastern Mediterranean locations as of December 31, 20182019 are shown on the map below:
Domestic and Regional Natural Gas DemandThe quantity of discovered natural gas resources at the Tamar and Leviathan fields has positioned Israel to meet domestic needs for decades and become a significant natural gas exporter. From offshore Israel projects, we have reliably delivered over 3.0 Tcf, gross, of natural gas primarily to Israeli customers, including the Israel Electric Corporation (IEC), the largest supplier of electricity in Israel. In mid-2019, the Tamar field achieved a milestone, reaching 2.0 Tcf of cumulative gross production with over 99% runtime since startup.
Leviathan Development ProjectIn order to expand Israel's supply of natural gas, create redundancy in infrastructure, and meet increasing regional demand, we progressed the initial phase of development at the Leviathan field, our largest discovery to date. We sanctioned the development in February 2017 and achieved first gas, ahead of schedule and under budget, with first production in December 2019.
The initial development includes four subsea wells, each capable of flowing more than 300 MMcf/d of natural gas. Production is gathered at the field and delivered via two 73-mile flowlines to a fixed platform, with full processing capabilities, located approximately 6 miles offshore. Processed gas connects to the Israel Natural Gas Lines Ltd. (INGL) onshore transportation grid at Dor, in the northern part of the country, and to regional markets via onshore and offshore export pipelines. The field began producing at the end of 2019 and will continue to ramp up to full production during 2020.
GSPAs and Regional TransportationTogether, the Tamar and Leviathan developments have total installed production capacity of approximately 2.3 Bcfe/d and are supplying natural gas under multiple long-term GSPAs to regional customers in Israel, Jordan and Egypt. Sales of natural gas to the National Electric Power Company Ltd. of Jordan began in January 2020. The gas is transported via the INGL grid to customers in Jordan and Egypt via the Arab Gas Pipeline and EMG Pipeline (defined below) systems. Sales to Egyptian customers have also begun via the EMG Pipeline.
During 2019, we and our partners amended the previously agreed GSPAs with our Egyptian customers. The amended agreements provide for total combined firm contract quantities of 3.0 Tcf of natural gas, gross, more than doubling the firm volume commitments previously agreed. In addition, each agreement has been extended by five years to reflect 15-year terms. These contracts allow for natural gas sales up to 650 MMcf/d, gross, by mid-2022. Increased export flow via the EMG Pipeline
In fourth quarter 2019, we have deliveredacquired an effective, indirect interest of approximately 2.65 Tcf, gross, of natural gas to Israeli customers, including the Israel Electric Corporation (IEC)10%, the largest supplier of electricitynet, in the country.entity that owns the EMG Pipeline (EMG Pipeline). We, along with parties to the transaction, including certain of our upstream partners, entered into an agreement to jointly operate the EMG Pipeline, securing access to the pipeline’s full capacity for a 10-year term, with extension terms available.
We are the first company to construct, operate and produce from a major energy development project offshore Israel. Our Mari-B discovery provided the country with its first supply of domestic natural gas in 2004. In 2009, we discovered the Tamar field, another substantial natural gas resource. To maintain and increase natural gas supply to Israel, we developed theRegional Expansion Opportunities Tamar field with a discovery to production cycle time of approximately four years, which is exceptionally fast by global industry standards for an offshore natural gas project of this magnitude and complexity.
In 2010, we discovered the Leviathan field,We expect our largest natural gas discovery to date. The quantity of discovered natural gas resources at Tamar and Leviathan positions Israel to meet domestic needs for decades and to become a significant natural gas exporter. Multiple natural gas customers exist in the region, and Israel’s domestic demand is predictedEastern Mediterranean business to continue to grow overin the next decade, primarily driven byfuture. In Israel, we expect continued coal conversion and increases in power, industrial, and transportation usage. In Jordan, we expect increasing industrialization leading to increased use of natural gas over coal to fuel electric power generation. During 2018, increased demand for electricity, continued coal displacement and almost 100% asset uptime, enabled us to set a new Tamar cumulative sales volume record of 1.75 Tcf gross. As customer demand increases and to reinforce the reliability of the Tamar project, we have continued to progress regulatory approvalconsumption. In Egypt, growth is anticipated in all market segments, with the Government of Israel regarding thecountry focused on becoming a regional natural gas hub. The Leviathan development plan allows for our 2013 Tamar Southwest discovery.
In addition to our natural gas discoveries, the Levant Basin is prospective for crude oil at greater depths. We conducted preliminary exploration activities in 2012 and, in 2018, continued analysis of potential forsignificant future exploration. See Item 8. Financial Statements and Supplementary Data – Note 7. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.Domestic Natural Gas DemandAs the Israeli economy continues to grow, the demand for natural gas used primarily for electricity generation is also expected to grow. Demand for natural gas in the industrial sector, including refineries, chemical, desalination, cement and other plants, as well as residential uses, is also increasing. These sectors are gaining confidence that a long-term supply of affordable natural gas will be available and are now investing the capital necessary to convert facilities and infrastructure to use natural gas. In addition, government requirements for emissions reductions have also driven incremental demand for natural gas beginning in 2016. We have executed numerous GSPAs with domestic customers. See Delivery Commitments – Israel Agreements.Regional Natural Gas Demand and Exports The Eastern Mediterranean presents an opportunity to match our affordable, abundant supply of natural gas with a substantially undersupplied regional market, including customers in Jordan and Egypt. With the Tamarcost-effective field online providing reliable production, and the development of the Leviathan field progressing, we are well positioned to supply natural gas to the region for many years. In first quarter 2018, we announced the execution of certain agreements to supply natural gascapacity expansion from the Leviathan and Tamar fields to customers in Egypt. See GSPAs and Transportation Agreements for Israeli Export, below.
Tamar Natural Gas Project (25% operated working interest) The Tamar project began production in March 2013 and has peak flow ratesits initial capacity of approximately 1.11.2 Bcf/d gross. In 2015, we completed the Tamar compression project, which expanded field production capacity by adding compression at the Ashdod onshore terminal (AOT). In 2017, we installed subsea equipment to connect the Tamar 82.1 Bcf/d. We are currently assessing future development well to the Tamar subsea system. Additionally, in 2017 we completed and commenced production from the Tamar 8 development well, which increases supply reliability as domestic demand for natural gas continues to grow.
In January 2019, the Petroleum Commissioner approved the development plan associated with our 2013 Tamar Southwest discovery, which includes the drilling of an additional development well to reinforce the reliability for the Tamar project and support increased customer demand.
expansions alternatives. We are also assessing the possibility for a Tamar expansion of the Tamar project. The project which could expand field deliverability from the current capacity level of approximately 1.21.1 Bcf/d up to approximately 2.12.0 Bcf/d, a quantity that could allowallowing for additional regional export. Expansion options could include additional investments in pipelines, wells, and platform upgrades. In January 2019, the Petroleum Commissioner of Israel approved the development plan for our Tamar Southwest discovery, which would access additional natural gas resources through a new well.
We also have significant discovered resources at the Aphrodite field, offshore Cyprus.In November 2019, we signed a PSC with the Government of Cyprus and were issued our exploitation license, which includes a development plan that would increase the delivery of natural gas to regional customers.
Timing of sanction for any expansion project sanction is dependent upon progress relating to domesticgas sales and regional marketing efforts of these resourcesmidstream agreements, as well as regulatory approvals from respective governments and capital allocation management.
The Israel Natural Gas Framework (Framework) provided for the reduction in our ownership interest in the Tamar field from 36% to 25% by year-end 2021. We completed the sell-down through a series of transactions, whereby we divested 3.5% of our interest in 2016, and in March 2018, we closed the sale of a 7.5% working interest in Tamar field to Tamar Petroleum Ltd (TASE: TMRP). Proved reserves related to the 7.5% interest sold total 502 Bcf, or approximately 84 MMBoe. In 2018, we also subsequently sold our investment in TMRP shares. See Item 8. Financial Statements and Supplementary Data – Note 5. Acquisitions and Divestitures.
Leviathan Natural Gas Project (39.66% operated working interest) In early 2017, we announced projectinternal company sanction of phase 1 of the Leviathan natural gas project and recorded initial proved reserves of 3.3 Tcf (551 MMBoe) associated with the first phase of development. The first phase of development of the Leviathan field provides 1.2 Bcf/d of production capacity and consists of four wells, a subsea production system and a shallow-water processing platform, with a connection to an onshore valve station and the Israel Natural Gas Lines (INGL) pipeline network.
We expect our share of development costs to total approximately $1.5 billion and remaining costs will be funded from our share of cash flows from the Tamar asset. As we progress through the initial phase of development, we have included volume capacity expansion optionality on the Leviathan platform to allow for cost effective expansion to meet growing regional natural gas demand.
As of December 31, 2018, the project is approximately 75% complete and remains on budget and on schedule. During 2018, we installed the in-field gathering and export pipelines, completed installation of all subsea trees, finished completions on all four wells with successful flowbacks, completed the float of the main decks and jacket rollup, flowline installation and completed jacket fabrication and sail-away. Project start up is anticipated by the end of 2019.
We are actively engaged in natural gas marketing activities to fill Leviathan Phase 1 capacity and have progressed multiple GSPAs with initial contracted quantities during 2020-2022 of up to approximately 922 MMcf/d, gross (approximately 320 MMcf/d, net) as of December 31, 2018 to supply customers in Israel, Jordan and Egypt.
GSPAs and Transportation Agreements for Israeli Export We have entered into a GSPA for the sale of 1.6 Tcf, gross (555 Bcf, net), of natural gas from the Leviathan field to the National Electric Power Company Ltd. (NEPCO) of Jordan, with pricing terms indexed to Brent crude oil. The agreement provides for sales of natural gas intended for consumption in power production facilities over a 15-year period. Sales to NEPCO are anticipated to commence at field startup.
In first quarter 2018, we executed two independent GSPAs for the sale of 2.3 Tcf, gross (651 Bcf, net), of natural gas from the Leviathan and Tamar fields to Dolphinus Holdings Limited to supply natural gas in Egypt. Sales volumes under the GSPA associated with the Leviathan field are anticipated to begin at a firm rate of approximately 350 MMcf/d, gross (approximately 121 MMcf/d, net), at the startup of the Leviathan project. For the Tamar agreement, sales volumes are anticipated to begin at an interruptible rate of up to 350 MMcf/d, gross (approximately 77 MMcf/d, net), dependent upon gas availability beyond existing customer obligations in Israel and Jordan. The GSPA includes an option to convert the Tamar interruptible quantity to a firm-basis with a take or pay commitment. Both contracts are for a 10-year term and have pricing terms indexed to Brent crude oil, similar to other export contracts in the region. The GSPAs are subject to satisfaction of conditions precedent, including regulatory approvals and licenses, and finalizing natural gas transportation agreements.
In September 2018, we announced the execution, along with certain third-parties, of agreements to support delivery of natural gas into Egypt. With certain partners, we plan to acquire a 39% equity interest in Eastern Mediterranean Gas Company S.A.E., which owns the EMG Pipeline. We will own an effective, indirect interest of approximately 10% net in the pipeline and, along with our partners, will enter into an agreement to exclusively operate the pipeline, securing access to the pipeline's full capacity. Closing of the agreement is subject to fulfillment of certain conditions precedent, which is expected in the first half of 2019, and our portion of estimated acquisition costs is approximately $200 million, net. Technical evaluation and flow reversal activities are currently underway.
We also received a letter of intent from the owner of the Aqaba-El Arish Pipeline to secure an option for additional capacity to transport natural gas within Egypt. This agreement will support transportation of natural gas to Egypt in addition to quantities supplied through the EMG Pipeline.
Alon D License In August 2017, the Petroleum Commissioner of Israel granted us a 32-month extension of the Alon D license (47.059% operated working interest) to drill an exploration well. As of December 31, 2018, we are in the process of relinquishing the license.
Dalit Discovery Our development plan for the Dalit field (25% operated working interest), a 2009 natural gas discovery, was approved by the Government of Israel. Development includes a tieback to the Tamar platform. We are also analyzing 3D seismic data to evaluate the additional potential of the area, including the possible existence of hydrocarbons at deeper intervals.
Israel Natural Gas Framework and Regulatory EnvironmentWe are subject to certain fiscal, antitrust and other regulatory challenges in Israel. These challenges have been addressed with the enactment of the Framework by the Government of Israel. See Regulations – Israel Regulatory Environment and Item 1A. Risk Factors – Our Eastern Mediterranean discoveries bear certain technical, geopolitical, regulatory, and financial challenges that could adversely impact our ability to monetize these natural gas assets.Cyprus Natural Gas Project (Offshore Cyprus)We continue to work with the Government of Cyprus on a plan of development for the Aphrodite field that, as currently planned, would deliver natural gas to regional customers. In addition, we
are focused on capital cost improvements, as well as natural gas marketing efforts and execution of natural gas sales and purchase agreements, which, once secured, will progress the project to a final investment decision.decisions.
West Africa (Equatorial Guinea, Cameroon and Gabon) West Africa includes the Alba field, Block O and Block I offshore Equatorial Guinea, the YoYo PSC,Block offshore Cameroon, and one block offshore Gabon. In West Africa, our interests can be burdened bymay differ due to overriding royalty interests and/or other government interests. As such, our working interests may differ from our revenue interests.
Equatorial Guinea is currently the only producing country in our West Africa segment and, excluding the impact of equity investees, Equatorial Guineainvestments, contributed an average of 5144 MBoe/d of sales volumes in 2018 and represented2019, representing approximately 15%12% of total consolidated sales volumes. At December 31, 2018,2019, Equatorial Guinea had proved reserves of 97132 MMBoe, which represents approximately 5%6% of total proved reserves. No wells were completed or participated in during the year.
Locations of our upstream operations in West Africa locations as of December 31, 20182019 are shown on the map below:
Aseng Field Aseng, is an oil field on Block I (40%(40% operated working interest, 38% revenue interest), offshore Equatorial Guinea, which began producing in 2011. The developmenton Block I, includes fivesix horizontal producing wells flowing to the Aseng floating production, storage and offloading vessel (FPSO) where the crude oil is stored until sold,offloaded and natural gas and water are reinjected into the reservoir to maintain pressure and maximize crude oil recoveries.sold. During 2018,2019, sales volumes from the Aseng field averaged 65 MBbl/d, net.
The Aseng FPSO is designed to act as a crude oil production hub, as well as a liquids storage and offloading facility, with capabilities to support future subsea oil field developments in the area. It also has the ability to process and store condensate from natural gas condensate fields in the area, the first of which is Alen. Since it first came online, the Aseng field has maintained reliable performance, averaging almost 100% production uptime and, as of December 31, 2018,2019, has produced over 95103 MMBbls of cumulative gross crude oil production.
In late 2018,third quarter 2019, we submitted a plan of development to the Government of Equatorial Guinea for the drilling of an additional crude oil development well. The well would be tied into existing subsea infrastructuredrilled and is expected to add crude oil reserves, minimize field declines and extend the reservoir life ofcompleted the Aseng field. We expect to sanction the project6P development well, which is mitigating field decline. First production began in the near future with first oil anticipated in latefourth quarter 2019.
Alen Field Alen is a natural gas and condensate field primarily on Block O (51% operated working interest, 45% revenue interest), offshore Equatorial Guinea,primarily on Block O which includes three production wells and three natural gas injection wells connected to a production platform. Condensate is pumped to the Aseng FPSO for storage and offloading. Alen has been producing since 2013 and salesSales volumes averaged approximately 23 MBbl/d, net, during 2018. As of December 31, 2018, Alen has produced over 36 MMBbls of cumulative gross condensate production.2019. The Alen platform is expected towill be utilized in our natural gas monetization efforts. See West Africa Natural Gas Monetization, below.
Alba Field Alba is a natural gas and condensate field located offshore Equatorial Guinea (33% non-operated working interest, 32% revenue interest). , which has been producing since 1991. Operations include the Alba field and related production and condensate storage facilities, a LPG processing plant where additional condensate is extracted along with LPGs, and a methanol plant capable of producing up to 3,100 gross metric tons per day of methanol.plant. The LPG processing plant and the methanol plant are located on Bioko Island, Equatorial Guinea. During 2018,2019, Alba field sales volumes averaged 5042 MBoe/d, net, reflecting 4336 MBoe/d, net, attributable to total consolidated sales volumes and 76 MBoe/d, net, attributable to an equity investee.investment.
We sell our share of primary condensate produced in the Alba field under short-term contracts at market-based prices. We sell our share of natural gas production from the Alba field to the LPG plant, the methanol plant, an unaffiliated liquefied natural gas (LNG) plant (EG LNG) and a power generation plant. The LPG plant is owned by Alba Plant LLC (Alba Plant), in which we have a 28% interest. Alba Plant sells its LPG products and secondary condensate at our marine terminal at prevailing market prices. The methanol plant is owned by Atlantic Methanol Production Company, LLC (AMPCO), in which we have a 45% interest. AMPCO purchases natural gas from the Alba field under a contract that runs through 2026 and subsequently markets the produced methanol primarily to customers in the US and Europe. Alba Plant sells its LPG products and secondary condensate at our marine terminal at prevailing market prices.
West Africa Natural Gas Monetization We continue efforts to monetize our significant natural gas discoveries offshore West Africa (YoYo, Yolanda and Felicita).
AAfrica. In second quarter 2019, we sanctioned the Alen natural gas development team has been working with local governments to evaluate natural gas monetization development plansdevelopment. Definitive agreements in support of the project were executed between the Alen field partners, the Alba Plant and progress negotiations of required contracts. In May 2018, we announcedEG LNG plant owners, as well as the execution, along with the Governmentgovernment of the Republic of Equatorial GuineaGuinea.
The development is designed to produce through three existing high-capacity wells and necessary third-parties, of a Heads of Agreement establishing the framework for development of naturalwill require minor platform modifications to deliver gas from the Alen field. The agreement outlinesfield to the high-level commercial terms for Alen natural gas to be processed through Alba Plant and Equatorial GuineaEG LNG Holdings Limited’sfacilities. The Alen field partners are developing a plan to construct a 24-inch pipeline capable of handling 950 MMcfe/d, gross, to transport natural gas processed through the Alen platform to the onshore facilities. First production is anticipated in the first half of 2021. At start-up, natural gas sales from the Alen field are anticipated to be between 200 and 300 MMcfe/d, gross (approximately 75 to 115 MMcfe/d, net). The wet gas stream will be tolled through the Alba Plant for additional liquids recovery before the dry gas is converted into LNG plant. Both plants are located in Punta Europa.at the EG LNG facility. The contemplated structure would result in Alen natural gas being marketed to global LNG customers. Sanction of
The Alen Gas Monetization is the project is contingent upon final commercial agreements being executed.
Existing production and processing facilities in place at the Alen platform and in Punta Europa require certain modifications to produce and process the Alen natural gas. The agreement contemplates construction offirst step towards creating a 65-kilometer pipeline to transportregional offshore natural gas fromhub, which will open the Alen platform topotential for future monetization of our additional discovered resources, such as at YoYo (YoYo Block, offshore Cameroon), Yolanda (Block I, offshore Equatorial Guinea) and Felicita (Block O, offshore Equatorial Guinea) through existing infrastructure. A data exchange agreement for the facilities in Punta Europa. We have awarded front-end engineering design (FEED) activities to progress the project to final investment decision, which is planned for 2019 with first gas anticipated in 2021.
Offshore CameroonWe have an interest in the YoYo PSC (100% operated working interest). The YoYo-1 exploratory well was drilled in 2007, discoveringYoYo/Yolanda condensate and natural gas discoveries has been executed between the governments of Equatorial Guinea and condensate. We areCameroon. Our development team is working with the government of Cameroonboth governments to evaluate natural gas development options, which will provide a more robust framework directly related to oil and gas operational activities.monetization options.
Offshore Gabon We are the operator of Block Doukou Dak (60% working interest), an undeveloped, deepwater area. Our exploration commitment includes an obligation for 3D seismic, which was acquired and processed throughout 2016 and the first half of 2017. We received the final product mid-year 2017 and are currently evaluating theacquired 3D seismic data results.data.
Other International Other international operations include the following:
Offshore ColombiaWe recently acquired a 40% operated working interest in more than two million gross acres offshore Colombia, located on two blocks, Colombia-3 and Guajira Offshore-3. Extensive 3D seismic data covering almost all of the
position has identified multiple large prospects. We continue well planning and permitting activities and expect to drill an exploration well in 2020. We will operate the blocks with Shell Exploration and Production GMBH as the other working interest owner.
Offshore Newfoundland (Canada) We have a non-operated 25% working interest in exploration licenses (EL) EL1145,EL 1145, EL 1146 and EL 1148, and a non-operated 40% working interest in EL 1149. BP Canada Energy Group ULC is the operator of the blocks. We licensed 3D seismic data to help us assessfor the purpose of assessing the economic viability of numerous exploration leads and prospects.
Offshore Suriname In October 2017, our partner spud the Araku-1 exploration well in Block 54 offshore in the Atlantic Ocean and subsequently plugged and abandoned the well. As a result, we recorded dry hole expense of $7 million in 2017. Based upon well results, modeling of the basin and review of further prospectivity, we released our non-operated 20% working interest and no longer have acreage offshore Suriname as of December 31, 2018.
Offshore Falkland Islands In 2016, following completion of our geological assessment, we exited all licenses, excluding the PL-001, which contained the Rhea prospect, and recorded $25 million of undeveloped leasehold impairment expense. In fourth quarter 2018, we provided notice to the Falklands government and exited our remaining license. As of December 31, 2018, we no longer have acreage offshore Falkland Islands.
North Sea The non-operated MacCulloch field is currently undergoing decommissioning activities. Due to its size and location, field abandonment is a multi-year process, requiring several phases. Therefore, our share of estimated field abandonment costs, recorded as an asset retirement obligation (ARO), may change over time.
Midstream – Properties and Activities
WeIn fourth quarter 2019, we concluded the sale of substantially all of our remaining US onshore midstream interests and assets and incentive distribution rights to Noble Midstream Partners. As we continue to developconsolidate Noble Midstream Partners, the activities related to these assets will continue to be reflected within our Midstream segment, which includessegment. See Item 8. Financial Statements and Supplementary Data – Note 4. Acquisitions and Divestitures.Noble Midstream PartnersNoble Midstream Partners is a publicly traded, consolidated subsidiary and limited partnership that constructs and operates a wide range of domestic midstream infrastructure assets, including two natural gas processing plants, gathering, treating, and transportation assets, as well as water-related infrastructure, including fresh water delivery and produced water disposal assets. Our Midstream assets are strategically located with our upstream development and production activities in the DJ and Delaware Basins and provideBasins. Noble Midstream Partners provides services to us and other third-party customers.
Midstream segment assets include the Black Diamond system, a large-scale integrated gathering system located in the DJ Basin (the Black Diamond System). The Black Diamond System is owned by Black Diamond Gathering LLC (Black Diamond), in which Noble Midstream Partners Our Midstream operations include those ofowns a 54.4% interest. Noble Midstream Partners operates the Black Diamond System and fully consolidates Black Diamond.
During 2019, Black Diamond entered into a publicly traded, consolidated subsidiarystrategic relationship with Saddlehorn Pipeline Company, LLC (Saddlehorn). Saddlehorn owns a pipeline that transports crude oil and limited partnership that constructscondensate from the DJ and operatesPowder River Basins to storage facilities in Cushing, Oklahoma. The strategic relationship includes a wide rangelong-term firm transportation commitment and the receipt, by Black Diamond, of domestic midstream infrastructure
assets. Noble Midstream Partners is a fee-based, growth-oriented Delaware master limited partnership formed in December 2014 organized in a development company structure. On September 20, 2016, Noble Midstream Partners completed its initial public offering of common units, which provided Noble Midstream Partners accessacquire up to the capital markets to support funding of its US onshore midstream investment program. At December 31, 2018, our20% ownership interest in Saddlehorn. In February 2020, Black Diamond exercised its option, acquiring a 20% ownership interest for $155 million ($84 million, net to Noble Midstream Partners consisted of a 45.4% limited partner interest, the entire non-economic general partner interest, and all incentive distribution rights.Partners).
In addition to developing and operating midstream assets, Noble Midstream Partners leveragedleverages its existing dedications and commercial relationships throughby investing in certain partnershipsentities providing transportation services downstream of our current operations. As ofDuring 2019, Noble Midstream Partners significantly expanded its equity holdings by acquiring equity interests in EPIC Crude Holdings, LP (EPIC Crude Holdings) and EPIC Y-Grade, LP (EPIC Y-Grade) and forming Delaware Crossing L.L.C. (Delaware Crossing). Equity method investments included the following at December 31, 2018,2019:
Advantage Pipeline L.L.C. (Advantage Pipeline), which owns a crude oil pipeline system in the southern Delaware Basin from Reeves County, Texas to Crane County, Texas (Advantage Pipeline System);
EPIC Y-Grade, which owns a Y-Grade pipeline from the Delaware Basin to Corpus Christi, Texas (EPIC Y-Grade Pipeline);
EPIC Crude Holdings, which is currently constructing a crude oil pipeline from the Delaware Basin to Corpus Christi, Texas (EPIC Crude Oil Pipeline); and
Delaware Crossing, which is currently constructing a crude oil pipeline and gathering system in the Delaware Basin.
In addition, Noble Midstream Partners has a 50% interest in Advantage Pipeline L.L.C. (Advantage Pipeline) in the Delaware Basin and a 3.33% interestan investment in White Cliffs Pipeline L.L.C. (White Cliffs) in, which owns a pipeline system from the DJ Basin. In first quarter 2019, we assigned Noble Midstream Partners our optionBasin to acquire a 30% equity interest in the EPIC Crude Oil Pipeline, and Noble Midstream Partners subsequently exercised this option with EPIC. Closing of Noble Midstream Partners’ equity interest in the EPIC Crude Oil Pipeline is anticipated in first quarter 2019 and subject to certain conditions precedent. Concurrently, Noble Midstream Partners exercised and closed its option with EPIC to acquire a 15% equity interest in the EPIC Y-Grade Pipeline. Cash consideration is expected to total approximately $330 million to $350 million for the interest in the EPIC Crude Oil Pipeline and approximately $165 million to $180 million for the interest in the EPIC Y-Grade Pipeline. Noble Midstream Partners intends to fund the equity investments with its revolving credit facility and/or additional sources of funding.Cushing, Oklahoma. See Item 8. Financial Statements and Supplementary Data – Note 5. Equity Method Investments5. Acquisitions for ownership percentages and Divestitures.investment balances. The following diagram depicts our organizational structure asIn addition to investing in midstream entities in 2019, Noble Midstream Partners focused on construction and development of December 31, 2018. Development companies identified in redmidstream infrastructure assets including trunk line extensions supporting future produced water gathering and blue indicate the location of the assets as eitherfresh water delivery services in the DJ or Delaware Basin, respectively.
Major Construction Projects Activity in 2018 primarily focused on construction and development of midstream infrastructure assets, including:
completed construction of the Collier, Billy Miner Train II and Coronado CGFs in the Delaware Basin;
completed construction of freshwater delivery infrastructure and commenced gathering services in the DJ Basin; and
signed a non-binding letter of intent with Salt Creek Midstream LLC (Salt Creek) for construction of a crude oil pipeline system in the Delaware Basin, for which definitive agreements with Salt Creek were executed in February 2019.
In 2019, we expect our midstream investment to continue to focus on the DJ and Delaware Basins to meet the needs of our upstream operations and third-party customers.
Noble Midstream Partners Saddle Butte Acquisition On January 31, 2018, Noble Midstream Partners acquired a 54.4% interest in Black Diamond Gathering LLC (Black Diamond), an entity formed by Black Diamond Gathering Holdings LLC, a wholly-owned subsidiary of Noble Midstream Partners, and Greenfield Midstream, LLC (Greenfield), which completed the acquisition of Saddle Butte from Saddle Butte Pipeline II, LLC (Saddle Butte Acquisition). Saddle Butte owned a large-scale integrated gathering system, located in the DJ Basin, which we subsequently renamed the Black Diamond gathering system. In addition to gathering services, certain oil purchases and sales occur within this business to better leverage existing infrastructure as well as to provide additional flexibility to Black Diamond's customer base. Cash consideration totaled $681 million, approximately $343 million of which was funded by Greenfield. Noble Midstream Partners operates the Black Diamond gathering system and we consolidate the entity for financial reporting purposes. See Item 8. Financial Statements and Supplementary Data – Note 5. Acquisitions and Divestitures.Other Noble Energy Midstream Assets Outside of Noble Midstream Partners and our interests in its development companies, we have retained full ownership in certain midstream businesses. Primarily, we own and operate two natural gas processing plants in the DJ Basin, crude oil gathering assets in the DJ and Delaware Basins, fresh water delivery assets in the Delaware Basin and gathering assets in the Eagle Ford Shale. We have granted rights of first refusal (ROFRs) on a combination of midstream assets retained by us outside of Noble Midstream Partners to provide midstream services on certain acreage and/or to acquire certain midstream assets.
Marcellus Shale CONE Gathering Divestiture In January 2018, we completed the sale of our 50% interest in CONE Gathering LLC (CONE Gathering) to CNX Resources Corporation and received proceeds of $309 million. After the sale, we held 21.7 million common units, representing a 34.1% limited partner interest, in CNX Midstream Partners LP (CNX Midstream Partners, NYSE: CNXM). We sold these units in 2018 receiving net proceeds of $387 million. The investment was previously accounted for under the equity method of accounting. See Item 8. Financial Statements and Supplementary Data – Note 5. Acquisitions and Divestitures.Third-Party Customers During 2018, Noble Midstream Partners continued providing crude oil and produced water gathering and fresh water delivery services to unaffiliated third parties in the Greeley Crescent IDP area of the DJ Basin. Additionally, the acquisition of interest in the Saddle Butte system has significantly increased the number of third-party customers across our Midstream segment.
Delivery Commitments
US Onshore Agreements Crude oil, NGLs, natural gas and condensate produced in theWe sell our US onshore are soldproduction under varyingvarious contracts, including short-term, long-term or life-of-field contracts, where all production from a well or group of wells is sold to one or more customers, at market-based prices adjusted for location and quality.quality differentials. Certain of our sales and delivery agreements may include natural gas processing or NGL fractionation commitments for the volumes delivered, either to a customer or to a service provider as assessed and accounted for under ASC 606.provider.
In addition, we have certain sales and delivery agreements to supply minimum quantities of production to various customers. The majority of our production is sold under short-term contracts. At December 31, 2018,2019, long-term (greater than one year) fixed sales commitments we were contractually committed to deliver included our five-year agreement which bringstwo agreements resulting in a portion of our Delaware Basin crude oil toproduction reaching the Texas Gulf Coast. Remaining quantitiesCoast, one with a remaining term of approximately four years and one with a remaining term of approximately two years. A total of approximately 40 MMBbls remain to be delivered under this agreement are 36.5 MMBbls.these contracts. We expect to fulfill thisthese delivery commitmentcommitments with existing proved developed and proved undeveloped reserves, which we regularly monitor to ensure sufficient availability to meet the commitments.
Israel AgreementsEastern Mediterranean GSPAs We currently sell natural gas from the Tamar field primarily to the IECcustomers in Israel, Egypt, and numerous other Israeli purchasers,Jordan, including state-owned power producers, independent power producers, cogeneration facilities, and industrial companies. Most contracts provide for the sale of natural gas over an initial term of one to 18 years. Some of the contracts provide for an increase or reduction in total quantities, and some contracts are interruptible during certain contract periods. SalesTypically, contracted sales prices may beare based on an initial base price subject to price indexation, Brent-linked or other, over the life of the contract and have a contractual floor. The IEC contract providesCertain contracts provide for price renegotiation in certain years with limits on the increase/decrease from the initial contractual price.
Under the contracts, we and our partners have financial exposure in the event we cannot fully deliver the contract quantities. This exposure is capped by contract and will be reflected as a reduction in sales price to the purchaser for periods in which we are delivering partial contract quantities, or as a direct payment to the customer under certain circumstances and with a cap.circumstances. The cap is subject to customary considerations including, but not limited to, force majeure considerations.provisions. We believe that any such sales price adjustments or direct payments would not have a material impact on our earnings or cash flows.
As of December 31, 2018,2019, a total of approximately 4.510.2 Tcf, gross (1.0(2.9 Tcf, net), of natural gas remained to be delivered under our Tamar contracts. Asthese contracts, which include new contracts relating to commencement of December 31, 2018, we have recorded 1.5 Tcf, net, of proved natural gas reserves, including proved developed reserves of 1.3 Tcf, net, and PUD reserves of 241 Bcf, net, forproduction at the TamarLeviathan field. Based on current production levels, and future development plans, our available quantities of provedproved reserves are more than sufficient to meet near-term delivery commitments associated with Tamar sales agreements without further capital investment. In addition, we have also executed certain interruptible GSPAs which would supply natural gas from Tamar.
We have also executed firm natural gasthese sales agreements for the sale of approximately 2.2 Tcf, gross (0.8 Tcf, net) of natural gas from the Leviathan field to customers in Israel and Jordan. Sales are anticipated to begin at the startup of the Leviathan project, currently projected for the end of 2019. As of December 31, 2018, we have recorded 3.3 Tcf, net, of PUD reserves for the Leviathan field related to sales to Israeli and Jordanian customers. See Eastern Mediterranean (Israel and Cyprus) - GSPAs and Transportation Agreements for Israeli Export.with minimal additional capital investment.West Africa Agreements Our share of crude oil and condensate from the Aseng, Alen and Alba fields is sold at market-based prices to Glencore Energy UK Ltd (Glencore Energy) and areis transported via tankers.
Natural gas from the Alba field is sold for $0.25 per MMBtu to a methanol plant, an LPG plant, an unaffiliated LNG plant and a power generation plant. The sales contract with the methanol plant runs through 2026, and the sales contract with the LNG plant runs through 2023. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method.
1. Summary of Significant Purchasers
Transportation Commitments
We have entered into various long-term firm transportation contracts, for some of our US onshore production. We use long-term contracts such as these to provide production flow assurance and ensure access to markets for our products at the best possible price and at the lowest possible logistics cost. These arrangementswhich represent commitments to pay transportation fees,fees; they are not commitments to deliver minimum volumes to end users.
Significant Purchasers
Regulations
Exploration for, and development, production and marketing of,The crude oil NGLs and natural gas areindustry is extensively regulated at the federal, state, and local levels in the US, and internationally. Regulations affecting elements of the crude oil and natural gas industryenergy sector are under constant review for amendment or expansion over time and frequently impose more stringent requirements on crude oil and natural gas companies.are imposed.
Various governmental bodies have issued rules, regulations and orders that require extensive efforts to ensure compliance, that impose incremental costs to comply, and that carry substantial penalties for failure to comply, which may impact our ability to economically produce and sell crude oil, NGLs and natural gas. Thesegas or conduct midstream operations. For example, these issuances may restrict the rate of crude oil, NGL 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 subjectIncreasing, and often
changing, governmental laws, regulations and environmentalother requirements that may restrict our access to land and/or cause us to incur substantial incremental costs.
Various domestic and international agencies have legal and regulatory authority and oversight over our exploration for, and productiondevelopment activities, as well as our midstream operations and sale of, crude oil, NGLs and natural gas.operations conducted by companies in which we invest, such as our equity method investments. Internationally, oversight also includes energy-related ministries or other agencies of our host countries, each having certain relevant energy or hydrocarbons laws. 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,Nasdaq Global Select Market, upon which shares of our common stock and common units of Noble Midstream Partners are traded.
Among the laws affecting our operations are the following:
Environmental Matters We take into account the cost of complying with environmental regulations in planning, designing, drilling, operating, and abandoning wells.wells, and in constructing and maintaining our midstream assets. In most instances, the regulatory requirements relate to the handling and disposal of drilling and production wastes, water and air pollution control procedures, facility siting and construction, protection of endangered species and their habitat, prevention of and responses to leaks and spills, and the remediation of petroleum-product contamination.remediation. These laws and regulations may require the acquisition of a permitpermits before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environmentemitted in connection with drilling and production activities, or limit or prohibit construction or drilling activities on certain lands lying within wilderness,protected by state or federal law, including designated critical habitat toof endangered or threatened species, wetlands, ecologically or seismically sensitive areas, and other protected areas,areas. Similarly, regulations may require action to prevent or remediate pollution from current, former or formeracquired operations, such as plugging abandoned wells or closing pits,pits. Failure to adhere to these regulations may result in the suspension or revocation of necessary permits, licenses and authorizations, require thator the requirement of additional pollution controls, be installed and imposeor the imposition of substantial liabilities for pollution resulting from our operations. Where our drillingoperational activities could result in a serious adverse effect upon a protected species, a federal or state agency could order a complete halt to such activities in certain locations or during certain seasons. Consequently, the presence of a protected species in areas where we operate could adversely affect future operations or production from those areas, and government agencies frequently add to the lists of protected species.
Under state and federal laws, and in foreign jurisdictions, we could be required to remove or remediate previously disposed wastes, including wastes disposed of or released by us, or by prior owners or operators,operators. Such activities must be performed in accordance with current laws and may cause us to suspend or cease operations in contaminated areas or to perform remedial well plugging operations or cleanups. TheFor example, the US Environmental Protection Agency (EPA) and various state agencies have limited the disposal options for hazardous and non-hazardous wastes and may continue to do so. The owner and operator of a site, and persons that treated, disposed of, or arranged for the disposal of hazardous substances found at a site, may be liable, without regard to fault or the legality of the original conduct, for the release of a hazardous substance into the environment. The EPA, state environmental agencies and, in some cases, third parties and foreign regulatory agencies, are authorized to take actions in response to threats to human health or the environment and to seek to recover from responsible classes of persons the costs of such action. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.
Furthermore, certainthough some exploration and production wastes are exempt from regulation as hazardous waste under Subtitle C of the Resource Conversation Recovery Act (RCRA), these wastes are generally subject to non-hazardous waste regulation under RCRA Subtitle D. Additionally, state governments have specific regulations and guidance for exploration and production wastes. As regulatory regimes are regularly revised, it is possible that in the future, wastes generated by our crude oil and natural gas operations that are currently exempt from the definition of hazardous waste may in the futurecould be subject to considerably more rigorous and costly operating and disposal requirements. Indeed,For example, legislation has been proposed from time to time in the US Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Also, inwastes”. In December 2016, the EPA agreed in a consent decree to review its regulationfederal regulations for the management of exploration, development, and production wastes of crude oil, natural gas, and gas waste. It has untilgeothermal energy under Subtitle D of RCRA. After review, the EPA concluded in March 2019 to determine whether anythat revisions are necessary.not necessary at this time.
Under federal and state occupational safety and health laws and laws of foreign jurisdictions in which we operate, we must develop and maintain information about hazardous materials used, released, or produced in our operations. Certain portions of this information must be provided to employees, state and local governmental authorities, and local citizens. We are also subject to the requirements and reporting set forth in federal workplace standards. Moreover, certain state or local laws or regulations and common law may impose liabilities in addition to, or restrictions more stringent than, those described herein.
We have made and will continue to make expenditures necessary to comply with environmental requirements. We do not believe that compliance with such requirements will have a material adverse effect on our capital expenditures, earnings or competitive position. Although such requirements do have a substantial impact on the crude oil and natural gas industry, they do not appear to affect us to any greater or lesser extent than other companies in the industry.
Apart from these federalthe above matters, most of the states where we operate have separate authority to regulate operational and environmental matters.
Colorado For some time, initiatives have been underway in the State of Colorado to limit or ban crude oil and natural gas exploration, development or operations, and/or to increase local, municipal authority or oversight over operations within their jurisdictions. In 2019, Senate Bill 19-181 (SB 181) was passed by the State Legislature and signed by the Governor into law. The legislation makes changes in Colorado oil and gas industry is regulated in part bylaw, including, among other matters, requiring the Colorado Oil and Gas Conservation Commission (COGCC)., which regulates the oil and gas industry in the State, to prioritize public health and environmental concerns in its decisions. The legislation also instructs the Colorado Air Quality Control Commission to adopt rules to minimize emissions of methane and other air contaminants and delegates considerable new authority to local governments to regulate surface impacts. The COGCC has initiated new rulemakings related to, among other things, incorporating new public health, safety, and environmental priorities into their regulations, updating wellbore integrity and flowline rules, and adopting new alternative location analysis and cumulative impact procedures. In December 2018,addition, some local communities have adopted further restrictions for oil and gas activities, such as requiring greater setbacks or increased bonding requirements, and other groups have sought a cessation of permit issuances entirely until the COGCC publishes new rules in keeping with SB 181.
Additionally, certain groups have indicated they plan to submit new ballot proposals for the 2020 election year, including proposals for increased drilling setbacks and increased bonding requirements.
The majority of our acreage in Colorado is in rural, unincorporated areas of Weld County, and we continue to work closely with local regulators and communities to ensure safe and responsible operations and future planning. At this time, we do not foresee significant changes to our development plans, as we have necessary approvals to drill wells over the next several years. The approved an increased setback distancepermits are for crude oilwells in multiple IDPs, many of which are in our Mustang CDP. We will continue to work closely with Weld County on the required local permits and natural gas wellsagreements for the CDP. However, if additional regulatory measures are adopted, we could incur additional costs to comply with the requirements or we may experience delays and/or curtailment in the permitting or pursuit of our exploration, development, or production activities. Such compliance costs and production facilities located in close proximity to schools baseddelays, curtailments, limitations, or prohibitions could have a material adverse effect on an expanded definitionour cash flows, results of “school facility.” Previously, the COGCC had allowed uniform setback distances of 500 feet from occupied buildingsoperations, financial condition, and 1,000 feet from high occupancy building units. The setback rules also require operators to utilize increased mitigation measures to limit potential drilling impacts and require advance notice to surface owners, owners of occupied building units, and local governments prior to the filing of an Application for Permit to Drill or liquidity. See Oil and Gas Location Assessment.Exploration and Production – Properties and Activities – US Onshore – DJ Basin. It is likely these types of initiatives will continue into the future in Colorado, and efforts by the US Administration to modify federal oil and gas related regulations could intensify the risk of anti-development efforts from grass roots opposition. See Item 1A. Risk Factors – Increasing trends of opposition to oil and gas development activity and negative public perception regarding us and/or our industry could have an adverse effect on our operations. The COGCC also has implemented rules makingwhich make Colorado the first state to require sampling of groundwater for hydrocarbons and other indicator compounds both before and after drilling. Further, the COGCC has adopted rules increasing the maximum penalty for violations of its requirements.
The state environmental agency, the Colorado Department of Public Health and Environment (CDPHE), likewise has adopted measures to regulate air emissions, water protection, and waste handling and disposal relating to our crude oil and natural gas
exploration and production. For air, the CDPHE has extended the EPA’s emissions standards for crude oil and natural gas operations to directly control methane.
In the state of Colorado, we have historically encountered initiatives to regulate limit or ban hydraulic fracturing or other facets of crude oil and natural gas exploration, development or operations. For example, in November 2018, a majority of Colorado voters voted against Proposition #112, which, if passed, would have significantly limited, or in some cases prevented, the future development of crude oil and natural gas and demand for our midstream services in areas where we currently conduct operations. If similar regulatory measures are adopted, we could 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.
It is likely these types of initiatives will continue into the future in Colorado, and efforts by the US Administration to modify federal oil and gas related regulations could intensify the risk of anti-development efforts from grass roots opposition. See Item 1A. Risk Factors – We face various risks associated with the trend toward increased anti-oil and gas development activity.hydrocarbon emissions.Some of the counties and municipalities where we operate in Colorado have adopted their own regulations or ordinances that impose additional restrictions on our crude oil and natural gas exploration and production. To date these have not significantly impacted our operations.
In April 2015, we entered into a joint consent decree (Consent Decree) with the EPA, US Department of Justice, and State of Colorado to improve emission control systems at a number of our condensate storage tanks that are part of our upstream crude oil and natural gas operations within the Non-Attainment Area of the DJ Basin. All fines required under the Consent Decree were paid in 2015; however, the required injunctive relief remainsactions are ongoing. We have concluded that the penalties, injunctive relief, plugging and abandonment activities, and mitigation expenditures that result from this settlement, based on currently available information, will not have a material adverse effect on our financial position, results of operations or cash flows. See Item 1A. Risk Factors – Our operations require us to comply with a numberViolations of certain US and international laws and regulations violations of which could result in substantial fines or sanctions and/or impair our ability to do business and Item 8. Financial Statements and Supplementary Data – Note 11.12. Commitments and Contingencies. Texas Texas has regulations governing conservation matters,of oil and gas resources, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells, the regulation of spacing, and requirements for plugging and abandonment of wells.
The oil and gas industry is regulated in part by the Texas Railroad Commission (RRC). The RRC requires Texas oil and gas operators to disclose on the FracFocus website chemical ingredients and water volumes used in hydraulic fracturing treatments. FracFocus.org is a public registry operated jointly by the Interstate Oil & Gas Compact Commission and the Ground Water Protection Council.
In addition, the RRC maintains a “well integrity rule” that addresses requirements for drilling, casing, and cementing wells. The rule also includes testing and reporting
requirements, including clarifying that cementing reports must be submitted after well completion or after cessation of drilling, whichever is earlier. Furthermore, the RRC oversees permit rules for injection wells to address seismic activity concerns within the state. Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells, and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. The RRC has used this authority to deny permits for waste disposal wells.
Israel Regulatory EnvironmentWe are subject to numerous regulatory measures in Israel, certain of which are governed by the Israel Natural Gas Framework (The Framework), as adopted by the Government of Israel. The Framework establishes policies for the development, production and supply of Israeli natural gas resources for both domestic and regional export sales. The Framework, among other things, provided for the sale of our ownership interest in the Karish and Tanin fields (which we completed in 2016) and the reduction of our ownership interest in the Tamar and Dalit fields to 25% by year end 2021 (which we completed in 2018), while enabling development and the marketing of Leviathan field natural gas to Israeli and export customers.
The oil and gas industry in Israel is regulated, in part, by the Ministry of Energy (MOE) and the Ministry of Environmental Protection (MOEP). The MOE has authority under the Petroleum Law of 1952 and the Natural Gas Market Law of 2002 to regulate oil and gas activities with its regulatory focus primarily relating to the engineering, operations, safety, hydrocarbon transmission, insurance, and royalty administration of oil and gas activities. The MOEP has authority under the Clean Air Law of 2008, the Law of Sea Pollution Prevention of 1988, the Hazardous Material Law of 1993, and the Business Licensing Law of 1968, and there are several other laws and international conventions that Israel has ratified. The MOEP primarily focuses on regulating the environmental impact of conducting business. These laws and international conventions set the parameters by which we are regulated through a series of regulations, guidelines, requirements, and permit approvals.
There are several other additional regulators, both federal (such as The Israeli Competition Authority, The Israeli Taxation Authority, and The Ministry of Defense) and local, that have jurisdictional authority over our assets and operations. Based on the location of the Leviathan platform within the territorial waters and the scale of our onshore footprint, these additional regulators, and in particular local authorities, have more recently required additional oversight of our operations.
Impact of Dodd-Frank Act Section 1504 Following a series of SEC actions, court proceedings and Congressional action, on December 18, 2019, the SEC voted to propose rules that would require resource extraction issuers, such as us, to disclose payments made to foreign governments or the US federal government for the commercial development of oil, natural gas, or minerals. The SEC first adopted rules in this area in 2012, as mandated by the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act). The 2012 rules were vacated by the US District Court for the District of Columbia. The SEC then adopted new rules in 2016, which were disapproved by a joint resolution of Congress pursuant to the Congressional Review Act.
Although the joint resolution of Congress vacated the 2016 rules, the statutory mandate remains in effect. As a result, the SEC is statutorily obligated to issue a rule. Under the Congressional Review Act, however, the SEC may not reissue the same rule in “substantially the same form” or issue a new rule that is “substantially the same” as the disapproved rule. The proposal will have a 60-day public comment period following its publication in the Federal Register. We will continue to monitor developments in this area.
Climate Change In recent years, the EPA has finalized a series of greenhouse gas (GHG) monitoring, reporting, and emissions control rules for the oil and natural gas industry, and the US Congress has, from time to time, considered adopting legislation to reduce emissions. In addition, almost one-half of the states have already taken measures to reduce emissions of GHGs, primarily through the development of GHG emission inventories and/or regional GHG cap-and-trade programs.
At the international level, in December 2015, the US signed the Paris Agreement on climate change and pledgedaimed to take effortsenhance global response to global temperature changes and to reduce GHG emissions, and to conserve and enhance sinks and reservoirs of GHGs. The Paris Agreement entered into force in November 2016. However, in August 2017,among other things. In 2019, the US notifiedbegan the United Nations that it would be withdrawingformal process to withdraw from the Paris AgreementAgreement. However, many states, city governments, non-governmental organizations and begin negotiationsother actors have pledged publicly to either re-enter or negotiate an entirely new agreementcontinue to align with more favorable terms for the US. The Paris Agreement sets forth a specific exit process, whereby a party may not provide noticeobjectives of its withdrawal until three years from the effective date, with such withdrawal taking effect one year from such notice. While the US Administration expressed a clear intent to cease implementing the Paris Agreement, it is not clear how it plans to accomplish this goal, whether a new agreement can be negotiated, or what terms would be included in such an agreement. Furthermore, in response to the announcement, many state and local leaders stated their intent to intensify efforts to uphold the commitments set forth in the international accord.
TheWhile we monitor climate-related regulatory initiatives and international public policy issues, the current state of development of the ongoing international climate initiatives and any related domestic actions make it difficult to assess the timing or effect on our operations or to predict with certainty the future costs that we may incur in order to comply with future international treaties, legislation or new regulations. However, future restrictions on emissions of GHGs, or related measures to encourage use of renewablelow carbon energy could have a significant impact on our future operations and reduce demand for our products. See also Item 1A. Risk Factors.Israel Regulatory Environment The Framework, as adopted by the Government of Israel, provides clarity on numerous matters concerning resource development, including certain fiscal, antitrust and other regulatory matters. The Framework provided for the reduction of our ownership interest in the Tamar and Dalit fields to 25% by year-end 2021, which we completed in 2018, while enabling the marketing of Leviathan natural gas to Israeli customers. See Item Financial Statements and Supplementary Data – Note 5. Acquisitions and Divestitures.Hydraulic Fracturing
Hydraulic fracturing techniques have been used for decades on the majority of all new onshore crude oil and natural gas wells drilled domestically. The process involves the injection of water, sand and chemical additives under pressure into targeted
subsurface formations to stimulate oil and gas production. We strive to adopt best practices and industry standards and comply with all regulatory requirements regarding well construction and operation. For example, the qualified service companies we use to perform hydraulic fracturing, as well as our personnel, monitor rate and pressure to assure that the services are performed as planned. Our well construction practices include installation of multiple layers of protective steel casing surrounded by cement that are specifically designed and installed to protect freshwater aquifers by preventing the migration of fracturing fluids into those aquifers. These processes are intended to minimize the risks associated with hydraulic fracturing. To help reduce our operational demand for freshwater and need for disposal, we are currently developing technology and infrastructure to expand our water recycling capacity in the DJ and Delaware Basins. We believe that these processes help ensure hydraulic fracturing is safe and does not and will not pose a risk to water supplies, the environment or public health.
All of the states where our US onshore operations are located (including Colorado and Texas) have developed hydraulic fracturing regulations. See Regulations - Colorado and Texas. Although hydraulic fracturing is regulated primarily at the state level, both Congress and government agencies at all levels from federal to municipal are studying the potential impacts of hydraulic fracturing, and some agencies have asserted regulatory authority over hydraulic fracturing and/or certain aspects of oil and gas operations connected with the hydraulic fracturing process. Some agencies have implemented new requirements, and some are evaluating the need for additional requirements. For example:legislation has been proposed in recent sessions of Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection,” to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in the fracturing process;process. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the Underground Injection Control program, specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act. In addition, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants.
Although hydraulic fracturing is regulated primarily at the state level, government agencies at all levels from federal to municipal frequently assess the potential impacts of hydraulic fracturing, and at times new requirements are proposed or implemented. For example:
the Bureau of Land Management (BLM), as a result of legal challenges, has published a final rule to rescind its 2015 rule governing hydraulic fracturing on federal and Indian lands. Further legal challenges are expected;lands; the rule was repealed in 2017, but state and environmental groups have challenged the rollback;
the Occupational Safety and Health Administration (OSHA) has lowered exposure limits for workers who use silica (sand) in, which can include hydraulic fracturing activities, and silica work practices have become stricter; and
state and federal regulatory agencies have focused on a possible connectionareas where there have been connections between hydraulic fracturing related activities, particularly the operation of injection wells used for oil and gas waste disposal or hydraulic fracturing activities, and seismic activity due to the presence of critically stressed faulting and orientation, which some have termed “induced seismicity,” and someseismicity”. Some state regulatory agencies have modified their regulations to account for such induced seismicity;seismicity and operators, including us, have implemented practices to avoid, monitor, mitigate and respond as necessary to induced seismicity.
ongoingOngoing or proposed studies on the environmental impacts of hydraulic fracturing could spur initiatives to further regulate hydraulic fracturing.
this activity. We currently disclose information regarding the components and chemicals used in the hydraulic-fracturing process for all US onshore areas in which we operate through the website for theFracFocus.org, a public registry FracFocus.org, which is operated jointly by the Interstate Oil & Gas Compact Commission and the Ground Water Protection Council.
Risk and Insurance Program
As protection against financial loss resulting from many, but not all operating hazards, we maintain insurance coverage, including certain physical damage, business interruption (loss of production income), employer's liability, third-party liability, worker's compensation insurance and certain insurance related to cyber security. We maintain insurance at levels that we believe are appropriate and consistent with industry practice. We regularly review our potential risks of loss and the cost and availability of insurance and the company's ability to sustain uninsured losses and revise our insurance program accordingly.
Availability of insurance coverage, subject to customary deductibles and recovery limits, for certain perils such as war or political risk is often excluded or limited within property policies. We are,have, however, actively looking to secure additional coveragespurchased insurance for certain political risks in Jordan and Egypt. In Israel, Egypt, and Equatorial Guinea, we insure against acts of war and terrorism in addition to providing insurance coverage for normal operating hazards facing our business. Additionally, as being part of
critical national infrastructure, the Israel offshore and onshore assets are included in a special property coverage afforded under the Israeli government's Property Tax and Compensation Fund Law; however, the amount of financial recovery through the fund is not guaranteed.
We have a risk assessment program that analyzes safety and environmental hazards, including cyber threats, and establishes procedures, work practices, training programs and equipment requirements, including monitoring and maintenance rules, for continuous improvement. We also use third-party consultants to help us identify and quantify our risk exposures at major facilities. We have a robust prevention program and continue to manage our risks and operations such that we believe the likelihood of a significant event is remote. However, if an event occurs that is not covered by insurance, not fully protected by insured limits or our non-operating partners are not fully insured, it could have a material adverse impact on our financial
condition, results of operations and cash flows. See Item 1A. Risk Factors -– The insurance we carry is insufficient to cover all of the risks we face, which could result in significant financial exposure. Competition
The crude oil and natural gas industry is highly competitive. We encounter competition from other crude oil and natural gas companies in all areas of operations, including the acquisition of seismic data and lease rights on crude oil and natural gas properties and for the labor and equipment required for exploration and development of those properties. Our competitors include major integrated crude oil and natural gas companies, state-controlled national oil companies, independent crude oil and natural gas companies, service companies engaging in exploration and production activities, drilling partnership programs, private equity, and individuals. Many of our competitors are large, well-established companies. Such companies may be able to pay more for seismic information and lease rights on crude oil and natural gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.
In addition, as we continue to expand our midstream services, we will face a high level of competition, including major integrated crude oil and natural gas companies, interstate and intrastate pipelines, and companies that gather, compress, treat, process, transport, store or market natural gas. As we seek to continue to provide midstream services to additional third partythird-party producers, we will also face a high level of competition. Competition is often the greatest in geographic areas experiencing robust drilling by producers and during periods of high commodity prices for crude oil, NGLs or natural gas or NGLs.gas.
See Item 1A. Risk Factors -– We face significant competition and many of our competitors have resources in excess of our available resources. Employees
As of December 31, 2018,2019, we had 2,3302,282 full-time employees.
Offices
Our principal corporate office is located at 1001 Noble Energy Way, Houston, Texas, 77070. We maintain additional regional offices in the US, Israel, Cyprus, Egypt, Colombia, Equatorial Guinea, and Cameroon.
Title to Properties
We believe that our title to the various interests set forth above is satisfactory and consistent with generally accepted industry standards, subject to exceptions that would not materially detract from the value of the interests or materially interfere with their use in our operations. Individual properties may be subject to burdens such as royalty, overriding royalty and other outstanding interests customary in the industry. In addition, interests may be subject to obligations or duties under applicable laws or burdens such as production payments, net profits interest, liens incident to operating agreements and for current taxes, development obligations under crude oil and natural gas leases or capital commitments under PSCs or exploration licenses. We have also dedicated certain of our US onshore acreage to Noble Midstream Partners for the provision of midstream services to us.
Furthermore, while our DJ Basin assets are primarily held by production, other assets, such as our Eagle Ford Shale and Delaware Basin properties are generally held primarily through continuous development obligations. Therefore, we are contractually obligated to fund a level of development activity in these areas or exercise options with land owners to extend leases. Failure to meet these obligations with respect to any particular lease may result in the loss of athat lease.
Title Defects Subsequent to a lease or fee interest acquisition transaction, the buyer usually has a period of time in which to examine the leases for title defects. Adjustments for title defects are generally made within the terms of the sales agreement, which may provide for arbitration between the buyer and seller.
Conflicts with Surface Rights Mineral rights are property rights that include the right to use land surface that is reasonably necessary to access minerals beneath. Lawsuits regarding conflicts between surface rights and mineral rights are currently
pending in several states. In several cases, owners of surface rights are suing various companies to prevent companies from using their land surface to drill horizontal wells to explore for or produce hydrocarbons from neighboring mineral tracts. If a plaintiff were to prevail in such a case, it could become more difficult and expensive for a company to place multi-acre well pads and/or limit the length of horizontal wells drilled from a pad.
Available Information
Our website address is www.nblenergy.com. Available on this website under “Investors – Financial Information – SEC Filings,” free of charge, are our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements, Forms 3, 4 and 5 filed on behalf of directors and executive officers, and amendments to those reports as soon as reasonably practicable after such materials are electronically filed with or furnished to the SEC. Alternatively, you may access these reports at the SEC’s website at www.sec.gov.
Also posted on our website under “Our Story – Transparency – Corporate Governance – Committee Charters,” and available in print upon request made by any shareholder to the Investor Relations Department, are charters for our Audit Committee, Compensation, Benefits and Stock Option Committee,Committee; Corporate Governance and Nominating Committee,Committee; and Safety, Sustainability and Corporate Responsibility Committee. Copies of the Code of Conduct and the Code of Ethics for Chief Executive and Senior Financial Officers (the Codes) are also posted on our website under the “Other Governance Documents” section. Within the time period required by the SEC and the NYSE,Nasdaq Global Select Market (Nasdaq), as applicable, we will post on our website any modifications to the Codes and any waivers applicable to senior officers as defined in the applicable Code, as required by the Sarbanes-Oxley Act of 2002.
Item 1A. Risk Factors
Described below are certain risks that we believe are applicable to our business and the oil and gas industry in which we operate. There may be additional risks that are not presently material or known. You should carefully consider each of the following risks and all other information set forth in this Annual Report on Form 10-K. If any of the events described below occur, our business, financial condition, results of operations, cash flows, liquidity or access to the capital markets could be materially adversely affected.
The oil and gas industry is cyclical and crudeCrude oil, NGL and natural gas prices are volatile. A reductionprice volatility, including a substantial or extended decline in the price of these pricescommodities, could have a material adverse effect on our results of operations, ourcash flows, liquidity, and the price of our common stock.
Our ability to operate profitably, maintain adequate liquidity, grow our cash flow and pay dividends or repurchase our common stock depend upon the prices we receive for our crude oil, NGL and natural gas production. Commodity prices are cyclical and subject to global supply and demand dynamics.
can fluctuate widely. A prolongedsubstantial or substantialprolonged decline in commodity prices, including declines in commodity forward price curves or volatility in location-basis differentials, may have the following effects, among others, on our business:
reduction of our revenues, profit margins, operating income, and cash flows;
reduction in the amount of crude oil, NGLs and natural gas that we can produce economically, leading to shut-in or early abandonment of producing wells, including low-margin US onshore wells, and increased capital requirements for abandonment operations;
certain properties in our portfolio becoming economically unviable;
impairments of proved or unproved properties or other long-lived assets;
use of cash flow to satisfy minimum obligations under throughput agreements if production is suspended;
delay, reduction, or suspension,cancellation of our future capital investment programs relating to our exploration and/or development projects, resulting in a reduced ability to develop or replace our reserves;
delay, postponement or cancellation of some of our exploration or development projects;
inability to meet exploration or continuous drilling commitments, leading to loss of leases or exploration rights;
loss of undeveloped acreage if we are unable to make scheduled delay rental payments or loss of developed acreage if our production is shut-in;
divestments of properties to generate funds to meet cash flow or liquidity requirements;
limitations on our financial condition, liquidity, including access to sources of capital, such as debt and equity, and/or ability to finance planned capital expenditures and operations;
failure of our partners to fund their share of development costs or obtain financing, which could result in delay or cancellation of future projects, thus limiting our growth and future cash flows;
inability to meet scheduled interest and/or debt payments or payments due under operating or capitalfinance leases;
a series of credit rating downgrades or other negative rating actions, which could increase our future cost of financing and may increase our requirements to post collateral as financial assurance of performance under certain other contracts, which, in turn, could have a negative impact on our liquidity and our ability to access the commercial paper market;
changes in corporate structure that could lead to loss of key personnel and interrupt our business activities;
reduction or suspension of dividends or repurchases of our common stock;
declines in our stock price; and
additional counterparty credit risk exposure on commodity hedges and joint venture receivables; and
a reduction in the carrying value of goodwill.receivables.
Our commodity price hedging arrangements in place will not fully mitigate the effects of price volatility and may also curtail benefits from future increases in commodity prices.
Markets and prices for crude oil, NGLs, and natural gas depend on factors beyond our control, factors including, among others:
global demand for crude oil, NGLs, and natural gas, as impacted by economic factors that affect gross domestic product growth rates of countries around the world;world, including impacts from global health epidemics and concerns, such as the coronavirus;
global supply for crude oil, NGLs, and natural gas, including inventories, as impacted by OPEC and non-OPEC countries (e.g. US, Russia, Canada);countries;
technology advances that increase crude oil, NGL, and natural gas production, thereby increasing supply;
new technologies that promote fuel efficiency or fuel efficiency regulations, such as the Corporate Average Fuel Economy (CAFE) standards, and impact demand for crude oil as a transportation fuel and reduce energy consumption;
the price and availability of alternative fuels and battery storage and the long-term impact on the crude oil market of the use of natural gas and electricity as an alternative fuel for road transportation or the use of natural gas as fuel for electricity generation impacting the demand for electricity;
developments in the global LNG market, including increasing exports from the US;
geopolitical conditions and events, including domestic political uncertainty or foreign generational leadership or regime changes, changes in government energy policies, including imposed price controls and/or product subsidies, the impact of trade embargoes or imposed tariffs, or instability/armed conflict in hydrocarbon-producing regions;
fluctuations in exchange rates of the US dollar, the currency in which the world's crude oil trade is generally denominated;
periods when production surpasses local pipeline/rail transportation and/or refining capacity, as is currently the case in the Delaware Basin, which in turn results in transportation constraints and significant discounts to our realized prices;
the level and effect of trading in commodity futures markets, including by commodity price speculators and others;
the effectiveness of worldwide conservation measures;
weather conditions;
access to government-owned and other lands for exploration and production activities; and
domestic and foreign governmental regulations and taxes.
Sector cost inflation could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.
Our industry is cyclical and third-party oilfield equipment materials and service costs are also subject to supply and demand dynamics. During periods of decreasing levels of industry exploration and production, the demand for, and cost of, drilling rigs and oilfield services decreases. Conversely, during periods of increasing levels of industry activity, the demand for, and cost of, drilling rigs and oilfield services increases. As a result, drilling rigs and oilfield services may not be available at rates that provide a satisfactory return on our investment.
As commodity prices have strengthened, the demand for oilfield services and infrastructure, particularly in US onshore basins, has risen, leading to cost inflation for the drilling, completion and operating of wells, and for the construction and/or access to necessary oil and gas infrastructure, including access to gathering facilities, transportation and/or takeaway pipelines driven by growing production volumes. Transportation bottlenecks or infrastructure limitations caused by the increased utilization may lead to competitive pricing pressures in certain basins. As a result, there is pressure on operating margins and capital efficiency in US onshore basins, including those in which we operate.
If this trend continues, and if commodity prices increase, we expect industry exploration and production activities to continue to increase, resulting in even higher demand for oilfield equipment services, which could result in significant sector price inflation. In addition, in basins of relatively higher activity, scarcity of competent service personnel may impact our ability to execute our exploration and development plans in a timely and profitable manner.
Concentration of capital in, and production and cash flows from, and capital in, certain operations may increase our exposure to risks enumerated herein.
A significant portion of our production and revenues is highly concentrated and is generated from a limited number of conventional deepwater wells. These wells, located offshore Israel and offshore Equatorial Guinea, contributed approximately 20% of our 20182019 total crude oil, NGL and natural gas revenues and 26%23% of our 20182019 total consolidated sales volumes. In
addition, we have a major concentration of reserves offshore Israel, with approximately 43%46% of our year-end 2018year end 2019 proved reserves attributable to this area.
These offshore projects are of such magnitude and scale and include significant operational technical complexities and dependencies on infrastructure, including subsea tiebacks to a FPSO or production platform, pressure maintenance systems, gas re-injection systems, limited onshore receiving terminals, or other specialized infrastructure. Although we carry contingent business interruption insurance for these producing assets, as well as other insurance, the insurance is insufficient to cover all potential risks.
We also have significant concentrations of capital and production in our US onshore unconventional basins including the DJ Basin, Delaware Basin and Eagle Ford Shale, and we expect to invest approximately 70%75% of our total capital investment program to development activities, primarily in these areasthe DJ and Delaware Basins, in 2019.2020. In addition, a significant portion of our proved reserves are in the DJ Basin with approximately 32% of our year-end 2019 proved reserves attributable to this area. Restrictions in land access or permitting, rapid changes in drilling and completion technology, significant increases in drilling and completion costs, lack of availability of downstream services, including access to gathering facilities, transportation and/or takeaway pipelines, lack of reliable power or electricity infrastructure, changes in regulations and other risks impacting these areas, as enumerated in certain risk factors described herein, can have immediate, significant negative impacts on our production, cash flows, profitability and financial position.
We face various risks associated with the trend toward increased anti-oilIncreasing trends of opposition to oil and gas development activity.activity and negative public perception regarding us and/or our industry could have an adverse effect on our operations.
In recent years, we have seen significant growth in opposition to oilanti-oil and gas development activity both in the US and globally.
Companies in our industry can be the target of opposition to hydrocarbon development from stakeholder groups, including national, state and local governments, regulatory agencies, non-government organizations and public citizens.development. This opposition is focused on attempting to limit or stop hydrocarbon development in certain areas. Examples of such opposition include: efforts to reduce access to public and private lands; restriction of exploration and production activities within government-owned and other lands; delaying or canceling permits for drilling or pipeline construction; limiting or banning industry techniques such as hydraulic fracturing, and/or adding restrictions on the use of water and associated disposal; imposition of set-backs on oil and gas sites; delaying or denying air-quality or siting permits; advocating for increased regulations, punitive taxation, or citizen ballot initiatives or moratoriums on industry activity; and the use of social media channels to cause reputational harm.
We have experienced these efforts in Colorado, recently and in the past, and it is likely they will continue into the future. For example, the State of Colorado General Assembly is currently developing a framework for future oilLegislature passed, and gas development in the State.Governor signed into law, SB 181. This initiative, together with increased
pressure to allow local governments to control oil and gas operations within their borders, could result in new regulations that limit or ban hydraulic fracturing or other facets of crude oil and natural gas exploration or development in areas where we operate. We cannot predict the outcome of these initiatives or their impact on our operations.
Our need to incur costs associated with responding to these anti-development efforts, including legal challenges, or complying with any new legal or regulatory requirements resulting from these efforts, could have a material adverse effect on our business, financial condition and results of operations.
Discoveries, development or acquisitions of reserves are needed to avoid a material decline in reserves and production.production and failure to adequately fund these activities could adversely affect our properties.
The productionProduction rates from oil and gas properties generally decline as reserves are depleted, while related per unit production costs generally increase due to decreasing reservoir pressures and other factors. Therefore, our estimated proved reserves and future crude oil, NGL and natural gas production will decline materially as reserves are produced unless we conduct successful exploration and development activities, such as identifying additional producing zones in existing fields, utilizing secondary or tertiary recovery techniques or gaining access to properties containing future proved reserves. Consequently, our future crude oil, NGL and natural gas production and related per unit production costs are highly dependent upon our level of success in finding or acquiring additional reserves.
The marketabilityOur exploration, development, and acquisition activities require capital expenditures to achieve production and cash flows. In particular, major offshore projects have a multi-year long development cycle time, which means that development spending occurs for several years before the project begins producing hydrocarbons and generating cash flows. For example, assets and infrastructure for the export of natural gas from Leviathan required a multi-billion dollar investment prior to production startup. With regard to onshore unconventional wells, these wells generally produce large volumes upfront and then deplete faster than conventional wells. As such, continuous drilling and capital investment may be required in order to maintain production levels. Furthermore, while our DJ Basin assets are primarily held by production, is dependent upon accessother assets, such as our Delaware Basin properties, are held primarily through continuous development obligations. Therefore, we are contractually obligated to gathering, transportationfund a level of development activity in these areas, the amount of which could be substantial, or to exercise options with land owners to extend leases. Failure to meet continuous development obligations or to exercise lease extensions may result in loss of leases. As a result, we will have less ability to replace our reserves through drilling operations and processing facilities, whichmay elect to forfeit our ownership interests or rights to participate in some properties, resulting in lower production over time as compared with prior years.
Historically, we may not own or control.have funded our capital expenditures through a combination of cash flows from operations, our Revolving Credit Facility (defined below), debt and equity issuances, and occasional sales of assets. Future cash flows from operations are subject to a number of variables, as enumerated herein. We evaluate capital spending levels based on the following factors, among others:
The marketability of our production from our US onshore areas depends in part upon the availability, proximity and capacity of gathering systems, transportation pipelines, rail service, and processing facilities. We delivercommodity prices, including price realizations on specific crude oil, NGLsNGL and natural gas producedproduction;
operating and development costs;
production, drilling and delivery commitments, or other contractual obligations;
drilling results;
cash flows from these areas through midstream infrastructure,operations and indebtedness levels;
availability of financing or other sources of funding;
impact of new laws and regulations on our business practices, including potential legislative or regulatory changes regarding the majorityuse of hydraulic fracturing;
property acquisitions and divestitures;
exploration activity; and
potential changes in the fiscal regimes of the US and other countries in which we operate.
We may be subject to risks in connection with acquisition and divestiture activities.
As part of our business strategy, we have made acquisitions of oil and gas properties and/or entities that own them. If we are unable to make attractive acquisitions, our future growth could be limited. Moreover, even if we do not own andmake acquisitions, they may not control.
We currently rely on state-owned pipeline and transportation systems to deliverresult in an increase in our natural gas productioncash flows from offshore Israel to customers and end usersoperations or otherwise result in the region. In addition, with the execution of multiple agreementsbenefits anticipated due to supply natural gas to customers in Egypt, we have entered into an agreement to acquire an equity interest in a company that owns the EMG Pipeline, which will connect the Israel pipeline network to Egyptian customers. Initial gas delivery through the EMG Pipeline is expected to occur in 2019various risks, including, but not limited to:
incorrect estimates or assumptions about reserves, exploration potential or potential drilling locations;
incorrect assumptions regarding future revenues, including future commodity prices and is pending certain conditions precedent. Offshore Equatorial Guinea, our natural gas production is delivered to onshore processingdifferentials, or regarding future development and storage facilities operated by our partner,operating costs;
incorrect assumptions regarding potential synergies and the resultingoverall costs of equity or debt;
difficulties in integrating the operations, technologies, products as well as our crude oil production from Aseng and Alen, are lifted to tankers owned by third-parties.personnel of the acquired assets or business; and
Third-party systemsunknown and facilitiesunforeseen liabilities or other issues related to any acquisition for which contractual protections prove inadequate, including environmental liabilities and title defects.
Such risks 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.
We have merged with or acquired other companies in the past. Prevention of a merger by antitrust laws could impair our ability to do business. Furthermore, mergers and acquisitions expose us to potential lawsuits or other obligations not yet anticipated at time of merger or acquisition. Such liabilities and obligations could hinder our ability to fully benefit from the acquired business or assets and negatively impact our financial performance.
The acquisition of a property or business requires management to make complex judgments and assessments, and the accuracy of the assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be consistent with industry practices. Our review will not reveal all existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities.
We also maintain an ongoing portfolio management program and we may notperiodically divest certain material assets. We strive to obtain the most attractive prices for our assets; however, various factors can materially affect our ability to dispose of assets on terms acceptable to us. Such factors may include:
current commodity prices;
laws and regulations impacting oil and gas operations in the areas where the assets are located;
willingness of the purchaser to assume certain liabilities such as asset retirement obligations;
our willingness to indemnify buyers for certain matters; and
delays in closing.
An 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 available to ussettled in the future at a priceamounts that is acceptable to us.are higher than we anticipated. In addition, the lack of availability of, or capacity on, third-party systemsalthough we may successfully divest oil and facilities, including those owned by Noble Midstream Partners, 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. Further, the inability of third-party processors, over whomgas assets, we have no control, to meet anticipated facility expansion deadlines, or to delay or even cancel projects, in areas where our production is growing,may retain certain related contracts, such as in the DJ Basin, could result in curtailment of our production growth and/or shut-in of production. Even where we have some contractual control over the transportation of our production through firm transportation arrangements, third-party systems and facilitiescontracts from divestiture of the Marcellus Shale upstream properties in 2017. In addition, we may be temporarily unavailable duerequired to market conditionsrecognize losses in accordance with exit or mechanical reliability or other reasons, including adverse weather conditions or geopolitical instability.
Our international operations may be adversely affected by economic or geopolitical developments or by violent acts such as civil disturbances, terrorist acts, regime changes, cross-border violence, war, piracy, or other conflicts.
We have significant international operations in Israel and Equatorial Guinea. We also conduct exploration activities in other international areas. Notwithstanding economic stability clauses, our operations may be adversely affected by social, economic or political developments, including the following:following, among others:
renegotiation, modification or nullification of existing contracts, which may occur pursuant to future regulations enacted as a result of changes in Israel's antitrust, export and natural gas development policies, or the hydrocarbons law enacted in 2006 by the government of Equatorial Guinea, which can increase the amount of revenues that the host government receives from production (government take) or otherwise decrease project profitability;
loss of revenue, property and equipment as a result of actions taken by host nations, such as expropriation or nationalization of assets or termination of contracts;contracts, which may cause a loss of revenue, property and equipment;
changes in drilling, environmental, social or safety regulations;
laws and policies of the US and foreign jurisdictions affecting trade, foreign investment, taxation and business conduct;
political conditions and events which may cause the potential for Israel natural gas production and regional exports to be interrupted by political conditions and events;interrupted;
difficulties enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations;operations which may cause difficulties enforcing our rights against a governmental agency;
US and international monetary policies impacting foreign exchange or repatriation restrictions in countries in which we conduct business; and
other hazards arising out of foreign governmental sovereignty over areas in which we conduct operations.
Such social, economic and political developments could have a negative impact on our results of operations and cash flows and reduce the fair values of our properties, resulting in impairment charges.
In addition, our international operations are located in, or are in close proximity to, regions that continue to experience varying degrees of political instability, public protests, territorial or boundary disputes, and terrorist attacks. Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as military or other actions taken in response to these acts, could
cause instability in the global financial and energy markets. Continued or escalated civil and political unrest and acts of terrorism in the regions in which we operate could result in curtailment of our operations. In the event that such regions experience civil or political unrest or acts of terrorism, especially in areas where such unrest leads to regime change, our operations there could be materially impaired.
We monitor the social, 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,effects, among others:others, on our business:
increased volatility in global crude oil, NGL and natural gas prices, which could negatively impact the global economy, resulting in slower economic growth rates, which could reduce demand for our products;
negative impact on the global crude oil supply if infrastructure or transportation are disrupted, leading to further commodity price volatility;
difficulty in attracting and retaining qualified personnel to work in areas with potential for conflict;
inability of our personnel, third-party providers or supplies to enter or exit the countries where we conduct 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 purchasers, leading to interruption of commodity deliveries, claims of force majeure, and/or termination of sales contracts, resulting in a reduction in our revenues;
lack of availability of drilling rigs, oilfield equipment or services if third-party providers decide to exit the region; and
shutdown of a financial system, communications network, or power grid causing a disruption to our business activities; and
capital market reassessment of risk and reduction of available capital making it more difficult for us and our partners to obtain financing for potential development projects.activities.
Loss of property and/or interruption of our business plans resulting from civil disturbances, terrorist acts, regime changes, war, or conflicts, or the threats thereof, 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.
Our Eastern Mediterranean discoveries bear certain technical, geopolitical, regulatory, and financial challenges that could adversely impact our ability to monetize these natural gas assets.
Due to the scale of our Leviathan (Israel) and Aphrodite (Cyprus) discoveries, realization of their full economic value depends on our ability to execute successful phased development scenarios, the failure or delay of which could reduce our future growth and have negative effects on our future operating results. Offshore projects of this magnitude entail significant technical complexities, including subsea tiebacks to a FPSO or production platform, pressure maintenance systems, gas re-injection systems, onshore receiving terminals, or other specialized infrastructure. In addition, we depend on third-party technology and service providers and other supply chain participants for these complex projects. Delays and differences between estimated and actual timing of critical events related to these projects could have a material adverse effect on our results of operations.
We have entered into and are currently negotiating various long-term GSPAs for our Eastern Mediterranean natural gas assets. Some of these agreements require the export of natural gas from either Israel or Cyprus to other countries in the region, such as Egypt and Jordan. These agreements are subject to a variety of risks, including geopolitical, regulatory, financial and other uncertainties. War, political violence, civil unrest or lack of intergovernmental cooperationuncertainties, and could affect both our and our counterparties’ abilities to cooperate and to perform under these agreements, andand/or could potentially lead to a breach or termination of such agreements. In addition, economic conditions or financial duress of our counterparties could jeopardize their ability to fulfill their payment obligations under these contracts. Furthermore, if material disruptions occur, including events or circumstances constituting force majeure under contract provisions, such that they inhibit us or our counterparties from performing under these GSPAs, or our counterparties are unable to pay us for a sustained period of time, we could incur a significant decline in revenues. While the State of Israel continues to maintain its ability to generate electricity via coal-fired power plants, as they transition from coal-fired power plants to natural gas-fired power plants, it is becoming more dependent on us and our partners for its source of natural gas supply. Any material disruption in our ability to deliver natural gas to the State of Israel could have a material impact on our expected profitability, financial performance and reputation.
A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss.
We are increasingly dependent on digital technology, including information systems and related infrastructure, as well as cloud applications and services, to process and record financial and operating data, communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of oil and gas reserves as well as other activities related to our business. Our business partners, including suppliers, service providers, purchasers of our production, and financial institutions, are also dependent on digital technology. The technologies needed to conduct oil and gas exploration and development activities in deepwater, ultra-deepwater and shale, as well as technologies supporting midstream operations and global competition for oil and gas resources make certain information the target of theft or misappropriation.
As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, 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. Supervisory control and data acquisition (SCADA) based systems are potentially vulnerable to targeted cyber attacks due to their critical role in operations.
Our technologies, systems, networks, and those of our business partners may become the target of cyber attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.
A cyber incident, involving our information systems and related infrastructure or that of our business partners, such as unauthorized access to seismic data, reserves information or other sensitive or proprietary information, data corruption, communication interruption, or other operational disruption, could disruptimpede our business plans and negatively impact our operations in the following ways, among others:
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 failure to reach the intended target or lead to a drilling incident;incident during drilling activities;
data corruption or operational disruption of production infrastructure could result in loss of production, or accidental discharge;discharge should production infrastructure be impacted;
a cyber attack on a supplier or service provider could result in supply chain disruptions which could delay or halt a development project, effectively delaying the start of cash flows from the project;
a cyber attack onprevent us from marketing our production through 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 networkcause operational disruption if communication networks or power grid could cause operational disruptiongrids are targeted resulting in loss of revenues;
a deliberate corruption of our financial or operational data, or data theft, could result in events of non-compliance which could lead to regulatory fines or penalties;penalties due to deliberate corruption of our financial or operational data, or data theft; and
business interruptions, including use of social engineering schemes and/or ransomware, could result in expensive remediation efforts, distraction of management, damage to our reputation, or have a negative impact on the price of our common stock.
Our implementation of various controls and processes to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure is costly and labor intensive. Moreover, there can be no assurance that such measures will be sufficient to prevent security breaches from occurring. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.
We are subject to increasingIncreasing, and often changing, governmental laws, regulations and environmentalother requirements that may restrict our access to land and/or cause us to incur substantial incremental costs.
Our industry is subject to complex laws and regulations adopted or promulgated by international, federal, state and local authorities relating to the exploration for, and the development, production and marketing of, crude oil, NGLs and natural gas. As the various government and/or regulatory bodies issue or rescind various regulations, our operations are subject to significant volatility in response to the issuance, interpretation and application of these regulations.
Examples of factors which reduce our land access, including loss of access to land for which we own mineral rights, reducedreduce our ability to obtain new leases, or loss ofreduce our rights granted under surface use agreements, rights-of-way, surface leases or other easement rights, include, among others:
new municipal, state or federal land use regulations, which may restrict drilling locations or certain activities such as hydraulic fracturing;
local and municipal government control of land or zoning requirements, which can conflict with state law and deprive land owners of property development rights;
landowner, community and/or governmental opposition to infrastructure development;
regulation of federal and Indian land by the BLM; and
the presence of threatened or endangered species or of their habitat.
In the state of Colorado, for example, since 2014 we have encountered citizen driven ballot initiatives and other legislative proposals to regulate, limit or ban hydraulic fracturing or other facets of crude oil and natural gas exploration, development or operations. See Items 1. and 2. Business and Properties – Regulations – Colorado. Changes in taxes, environmental laws or implementation of price controls taxes and environmental laws relating to our industry also have the ability to substantially affect crude oil, NGL and natural gas production, operations and economics. Environmental laws, in particular, can change frequently, often become stricter and at times may force us to incur additional costs as changes are implemented.
Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Additionally, the accidental and/or unpermitted discharge of natural gas, crude oil, or other pollutants into the air, soil or water may give rise to liabilities on our part to government agencies and/or third parties, and may require us to incur costs to achieve remediation objectives and/or
Noncompliance with existing or future legislation or regulations could potentially result in an increased risk of civil or criminal fines or sanctions. Fines or sanctions associated with a well incident or spill could well exceed the actual cost of containment and cleanup. In addition, we cannot always predict with certainty how agencies or courts will interpret existing laws and regulations or the effect these interpretations may have on our business or financial condition.
Restricted land access, further expansion of environmental, safety and performance regulations or an increase in liability for drilling or production activities, including punitive fines, may have one or more of the following impactseffects, among others, on our business:
reduce our proved reserves;
reduce our ability to explore for new proved reserves;
increase exploratory and development well drilling costs, operating or other costs;
delay, or preclude, project development resulting in longer development cycle times;
disrupt or prohibit our ability to construct or operate midstream assets;
divert our cash flows from capital investments in order to maintain liquidity;
increase or remove liability caps for claims of damages from oil spills;
increase our share of civil or criminal fines or sanctions for actual or alleged violations if a well incident were to occur; and
limit our ability to obtain additional insurance coverage, at a level that balances the cost of insurance and our desired rates of return, to protect against any increase in liability.
Any of the above operating or financial factorsimpacts could have a material adverse effect on our business, financial condition, results of operations, and cash flows and may result in a reduction of the fair value of our properties or reduce our financial flexibility. Because we strive to achieve certain levels of return on our projects, an increase in our financial responsibility could result in certain of our planned projects becoming uneconomic. See Items 1. and 2. Business and Properties – Regulations. Our operations may be adversely affected by changesA change in the fiscal regimes and related government policies, tax laws and regulations in the US and other countries in which we operate.operate may adversely affect our results of operations and financial condition.
Fiscal regimes impact oil and gas companies through laws and regulations governing resource access, along with government participation in oil and gas projects, royalties and taxes. We operate in the US and other countries whose fiscal regimes may change over time. Changes in fiscal regimes result in an increase or decrease in the amount of government financial take from developments, and a corresponding decrease or increase in the revenues of an oil and gas company operating in that particular country. For example, a significant portion of our production comes from Israel and Equatorial Guinea; therefore, changes in or uncertainties related to the fiscal regimes or energy policies of these countries could delay or reduce the profitability of our development projects, and/or render future exploration and development projects uneconomic.
The elimination of tax deductions, as well as any other changes to or the imposition of new federal, state, local or non-US taxes (including the imposition of, or increases in production, severance or similar taxes) could also have a significant impact on our operations and financial performance. For example, on December 22, 2017, the US Congress enacted tax reform legislation known as the Tax Cuts and Jobs Act (Tax Reform Legislation). The Tax Reform Legislation is complex and far-reaching makingand made sweeping modifications to the Internal Revenue Code including a lowerlowering the corporate tax rate, changes tochanging credits and deductions, and a movemoved to a territorialsemi-territorial system for corporations that have overseas earnings.
Periodically, other legislative amendments may be proposed that, if enacted into law, would make additional significant changes to US federal and state income tax laws, such as (i) the elimination of the immediate deduction for intangible drilling and development costs and (ii) an extension of the amortization period for certain geological and geophysical expenditures. No accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future, or the timing of any such action. Further, we cannot predict how government agencies or courts will interpret existing regulations and tax laws, including the Tax Reform Legislation, or the effect such interpretations could have on our business.
Changes in fiscal regimes, including changes in tax laws and regulations, have long-term impacts on our business strategy, and fiscal uncertainty makes it difficult to formulate and execute capital investment programs. The implementation of new, or the modification of existing, laws or regulations increasing the tax costs on our business could disrupt our business plans and negatively impact our operations and our stock pricebusiness in the following ways, among others:
restrict resource access or investment in lease holdings;
limit or cancel exploration and/or development activities, which could have a long-term negative impact on thefuture quantities of proved reserves we record and inhibit future production growth;
negatively impact our and/or our partners' ability to obtain financing;
reduce the profitability of our projects, resulting in decreases in net income and cash flows with the potential to make future investments uneconomical;
result in currently producing projects becoming uneconomic, to the extent fiscal changes are retroactive, thereby reducing the amount of proved reserves we record and cash flows we receive, and possibly resulting in asset impairment charges;
require that valuation allowances be established against deferred tax assets, with offsetting increases in income tax expense, resulting in decreases in net income and cash flow; and/or
restrict our ability to compete with imported volumes of crude oil or natural gas.
A change in international and/or US federal and state climate policy could have a significant impact on our operations and profitability.financial condition.
Domestic and international responses to climate and related energy issues are matters of public policy consideration. We are currently in a period of increasing uncertainty as to these matters and, at this time, itIt is difficult to anticipate how the current or future US Administration, or other entities, may act on existing or new laws and regulations. As compared with certain large multi-national, integrated energy companies, we do not conduct fundamental research regarding the scientific inquiry of climate change. However, we will continue to closely monitor all relevant developments in this regard. Changes in international, federal or state laws and regulations regarding climate policy could have a significant negative impact on our ability to explore for and develop crude oil and natural gas resources or reduce demand for our products.
In recent years, international, federal, state and local governments have taken steps to reduce emissions of greenhouse gases. The EPA has finalized a series of greenhouse gas monitoring, reporting and emissions control rules for the oil and natural gas industry, and the US Congress has, from time to time, considered adopting legislation to reduce emissions. Almost one-half of statesStates in the US have also taken measures to reduce emissions of greenhouse gases primarily through the development of greenhouse gas emission inventories and/or regional greenhouse gas cap-and-trade programs. For a description of existing and proposed greenhouse gas rules and regulations, see Items 1. and 2. Business and Properties – Regulations. Furthermore, claims have been made against certain energy companies alleging that greenhouse gas emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or other entities may make claims against us for alleged personal injury, property damage, or other potential liabilities. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could impact our operations and could have an adverse impact on our financial condition.
Additionally, there has been public discussion thatabout climate change may be associated withand the increase of extreme weather conditions such as more intense hurricanes, thunderstorms, flooding, tornadoes, drought and snow or ice storms, as well as rising sea levels. Extreme weather conditions can interfere with our production and increase our costs, and damage resulting from extreme weather may not be fully insured.
Our operations require usFederal, state and local hydraulic fracturing and water disposal legislation and regulation could increase our costs or restrict our ability to comply withproduce crude oil, NGLs and natural gas economically and in commercial quantities.
Certain parties have called for further study of hydraulic fracturing's alleged environmental and health effects, for additional regulation of the technique and, in some cases, for a moratorium or ban on the use of hydraulic fracturing. Because of elevated public sensitivity around the topic, federal, state and local governments are continually conducting studies, evaluating their regulatory programs and considering additional requirements on and regulation of hydraulic fracturing practices. At the national level, proposals have been introduced from time to time in the US Congress that, if implemented, would subject hydraulic fracturing to further regulation, thereby limiting its use or increasing its cost.
In Colorado, a number of local communities have attempted to increase regulatory requirements on crude oil and natural gas development, certain of which have succeeded, and the use of hydraulic fracturing on federal lands continues to be a topic of political interest. In addition, some state regulatory agencies have modified their regulations to account for potential induced seismicity with regard to the operation of injection wells used for waste disposal.
We are dependent on the use of hydraulic fracturing practices to produce commercial quantities of crude oil and natural gas, particularly from wells in our US onshore basins. Additional federal, state or local restrictions on hydraulic fracturing, water disposal or other drilling activities that may be imposed in areas where we conduct business, such as US onshore, could significantly increase our operating, capital and compliance costs, as well as delay or halt our ability to develop crude oil, NGL and natural gas reserves. See Items 1. and 2. Business and Properties – Regulations and – Hydraulic Fracturing. Exploration, development and production activities carry inherent risk. These activities, as well as natural disasters or adverse weather conditions, could result in liability exposure or the loss of production and revenues.
Our operations are subject to hazards and risks inherent in the drilling, production and transportation of crude oil, NGLs and natural gas, including, among others:
pipeline ruptures and spills;
fires, explosions, blowouts and well cratering;
equipment malfunctions and/or mechanical failure on high-volume, high-impact wells;
malfunctions of, or damage to, gathering, processing, compression and transportation facilities and equipment and other facilities and equipment utilized in support of our operations;
leaks or spills occurring during the transfer of hydrocarbons from an FPSO to an oil tanker;
loss of product occurring as a result of transfer to a truck or rail car or train derailments;
leakage or loss of access to hydrocarbons resulting from formations with abnormal pressures and basin subsidence;
release of pollutants; and
spills, leaks or discharges of fluids used in or produced in the course of operations, especially those that reach surface water or groundwater.
Some of these risks or hazards could materially and adversely affect our revenues and expenses by reducing or shutting in production from wells, causing the loss of equipment or otherwise negatively impacting the projected economic performance of our projects. In addition, our ability to deliver product pursuant to long-term supply contracts could be negatively impacted, resulting in additional financial exposure in the event we cannot fully deliver the contract quantities.
Our operations and financial results could also be significantly impacted by adverse weather conditions and natural disasters in the areas we operate including:
hurricanes, tropical storms, windstorms, flooding or “superstorms,” which could affect our operations in Texas;
winter storms and snow, which could affect our operations in the DJ Basin;
extremely high temperatures, which could affect our midstream or third-party gathering and processing facilities in the DJ Basin and Texas;
severe droughts, which could result in new restrictions on water usage in the DJ Basin and Texas;
harsh weather and rough seas offshore international locations, which could limit exploration activities; and
other natural disasters.
Any of these risks or hazards can result in injuries and/or deaths of employees, supplier personnel or other individuals, loss of hydrocarbons, environmental pollution and other damage to our properties or the properties of others, regulatory investigations and administrative, civil and criminal penalties or restricted access to our properties.
Development drilling may not result in commercially productive quantities of crude oil and natural gas reserves from unconventional or conventional resources.
We depend on development projects to provide sustained cash flows after investment and attractive financial returns. However, development drilling is not always successful and the profitability of development projects may change over time.
In new development areas, including certain shale formations, available data may not allow us to know the extent of the reservoir or the best locations for drilling development wells. Therefore, a development well we drill, or in which we participate, may be a dry hole, may result in noncommercial quantities of hydrocarbons or may be less productive than our initial estimates.
We expect to invest significant amounts of capital to continue development of our US onshore unconventional resources. In unconventional basins, development is highly dependent on costs of equipment and services, the use of technologies to drive capital and cost efficiencies in drilling and completion, and the availability of and access to midstream infrastructure. Even if development drilling is successful and we find commercial quantities of reserves, we may encounter difficulties or delays in completing development wells. For example, frontier areas or less developed onshore areas may not have adequate infrastructure for gathering, transportation or processing, and production may be delayed until such infrastructure is constructed.
Exploratory drilling subjects us to risks and may not result in the discovery of commercially productive reservoirs.
Exploratory drilling requires significant capital investment and does not always result in commercial quantities of hydrocarbons or new development projects. In addition, exploratory drilling activities may be curtailed, delayed or canceled, or development plans may change, resulting in significant exploration expense, as a result of a variety of factors, including unexpected drilling conditions and pressure or other irregularities in formations. Furthermore, remote locations may make it more difficult and time-consuming to transport personnel, equipment and supplies, and we may face more difficult environments, such as oil sands, deepwater, or ultra-deepwater, in our efforts to seek new reserves, and may need to develop or invest in new technologies. These operating environments, and the potential for harsh weather, increase cost as well as drilling risk.
Exploratory dry holes can occur because seismic data and other technologies we use to determine potential exploratory drilling locations do not allow us to know conclusively prior to drilling a well that crude oil or natural gas is present or may be produced economically. In addition, a well may be successful in locating hydrocarbons, but we and our partners may decide not to develop the prospect due to other considerations.
In addition, for certain capital-intensive offshore projects, it may take several years to evaluate the future potential of an exploratory well and make a determination of its economic viability, resulting in delays in cash flows from production start-up and a lower return on our investment.
We hold working interests in certain areas, including offshore areas of Cyprus, Cameroon, Colombia, Gabon and Newfoundland (Canada) where there is minimal or no crude oil, NGL or natural gas production, and in certain cases, limited infrastructure. If commercial quantities of hydrocarbons are discovered, areas with minimal or no current production must begin to address topics such as sector regulation and distribution of government proceeds from hydrocarbon sales, the results of which could have a negative impact on our business. We may not be able to compensate for or fully mitigate these risks. See Item 8. Financial Statements and Supplementary Data – Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs. Our receivables, hedging transactions and cash investments expose us to counterparty credit risk.
We are exposed to risk of financial loss from trade, joint venture and other receivables. We sell production to a variety of purchasers and as operator, we pay joint venture expenses and make cash calls on nonoperating partners for their respective shares of joint venture costs. Certain of these counterparties may experience insolvency, liquidity problems or other issues and may not be able to meet their obligations and liabilities owed to us timely or at all.
We have cash and cash equivalents deposited with financial institutions and engage in hedging activities, both of which may expose us to counterparty credit risk or, in some cases, cause us to incur significant cash settlements. As an entity entering into derivatives transactions under master agreements that are subject to US laws, we are subject to some limitations on our ability to exercise default rights with respect to derivatives transactions with a financially-troubled bank. On January 1, 2019, the US Bank Regulators imposed additional restrictions on counterparties that are parties to certain types of Qualified Financial Contracts (QFCs) with major banks that have been designated as Global Systemically Important Banks (G-SIBs). These QFCs include various master agreements and the financial derivatives transactions that are entered into under such master agreements with G-SIBs as counterparties.
While we monitor the creditworthiness of purchasers, joint venture partners, banks and financial institutions with which we conduct business, we are unable to predict sudden changes in solvency of these counterparties and may be exposed to associated risks. Credit enhancements have been obtained from some parties in the form of parental guarantees, letters of credit or credit insurance. However, not all of our counterparty credit is protected through guarantees or credit support. In addition, we maintain credit insurance associated with specific purchasers. However, nonperformance by a purchaser, hedge counterparty or financial institution could result in significant financial losses.
Violations of certain 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 generally prohibit improper payments to foreign officials for the purpose of obtaining or keeping business. We conduct some of our operations in developing countries that have relatively underdeveloped legal and regulatory systems compared to more developed countries. These countries generally are perceived as presenting an increased risk of corruption. Additionally, certain of our operations involve the use of agents and other intermediaries whose conduct and actions could be imputed to us by anti-corruption enforcement authorities. Violations of the FCPA or other anti-corruption laws could subject us to substantial fines or sanctions and impair our ability to do business.
The import/export of equipment and supplies necessary for oil and gas exploration and development activities, as well as the export of crude oil, liquids and natural gas production are regulated by the import/export laws of the US and other countries in which we operate. In the US, certain items required for oil and gas development activities may be considered “dual-use”, having both commercial and military applications and, therefore, may be subject to specific import or export restrictions. In addition, the US government imposes economic and trade sanctions against certain foreign countries and regimes. The sanctions are based on US foreign policy and national security goals and may change over time.
As a developer, owner and operator of crude oil and natural gas properties, we are subject to various laws and regulations relating to the discharge of materials into, and the protection of, the environment. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. See We are subject to increasingIncreasing, and often changing, governmental laws, regulations and environmentalother
Federal, stateThe marketability of our production is dependent upon access to gathering, transportation and local hydraulic fracturingprocessing facilities, which we may not own or control.
The marketability of our production from our US onshore areas depends in part upon the availability, proximity and water disposal legislationcapacity of gathering systems, transportation pipelines, rail service, and regulation could increase our costs or restrict our ability to produceprocessing facilities. We deliver crude oil, NGLs and natural gas economicallyproduced from these areas through midstream infrastructure, the majority of which we do not own and in commercial quantities.may not control.
While hydraulic fracturing has been utilized in oilInternationally, we rely on third-party pipeline and transportation systems, some of which are foreign government-owned or influenced, to deliver our natural gas development for decades, certain parties have called for further study of the technique's alleged environmentalproduction from offshore Israel to customers and health effects, for additional regulation of the technique and, in some cases, for a moratorium or ban on the use of hydraulic fracturing. Because of elevated public sensitivity around the topic, federal, state and local governments are continually conducting studies, evaluating their regulatory programs and considering additional requirements on and regulation of hydraulic fracturing practices. At the national level, proposals have been introduced from time to timeend users in the US Congress that, if implemented, would subject hydraulic fracturingregion, including Israel, Jordan and Egypt. Offshore Equatorial Guinea, our natural gas production is delivered to further regulation, thereby limiting its use or increasing its cost.
Federal agencies addressing hydraulic fracturing under existing authorities include the EPAonshore processing and storage facilities operated by our partner, and the BLM, under the US Department of the Interior. In 2017, an executive order was signed directing the EPA and the BLM to review their rules and, if appropriate, initiate rulemaking to rescind or revise them consistent with the stated policy of promoting clean and safe development of the nation’s energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production. Accordingly, the EPA and the BLM have taken actions to delay or rescind certain requirements related to hydraulic fracturing activities. See Items 1. and 2. Business and Properties – Hydraulic Fracturing.Each of the states,resulting products, as well as certain localities, where we operate have adopted or may adopt regulations on drilling activities in general or hydraulic fracturing in particular that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, a number of local communities in Colorado have attempted to increase regulatory requirements on crude oil and natural gas development. In addition, some state regulatory agencies have modified their regulations to account for potential induced seismicity with regard to the operation of injection wells used for waste disposal.
Furthermore, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. On December 13, 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. Also, on February 6, 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental agencies, including the US Department of Energy, the US Geological Survey, and the US Government Accountability Office, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing, and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.
We are dependent on the use of hydraulic fracturing practices to produce commercial quantities of crude oil and natural gas, particularly from wells in our US onshore basins. Additional federal, state or local restrictions on hydraulic fracturing, water disposal or other drilling activities that may be imposed in areas where we conduct business, such as US onshore, could significantly increase our operating, capital and compliance costs, as well as delay or halt our ability to develop crude oil, NGL and natural gas reserves. See Items 1. and 2. Business and Properties – Regulations and – Hydraulic Fracturing.Exploration, development and production activities carry inherent risk. These activities, as well as natural disasters or adverse weather conditions, could result in liability exposure or the loss of production and revenues.
Our operations are subject to hazards and risks inherent in the drilling, production and transportation of crude oil, NGLs and natural gas, including:
pipeline ruptures and spills;
fires, explosions, blowouts and well cratering;
equipment malfunctions and/or mechanical failure on high-volume, high-impact wells;
malfunctions of, or damage to, gathering, processing, compression and transportation facilities and equipment and other facilities and equipment utilized in support of our crude oil NGLproduction from Aseng and natural gas operations;Alen, are lifted to tankers owned by third-parties.
leaks or spills occurring during the transfer of hydrocarbons from an FPSOThird-party systems and facilities may not be available to an oil tanker;
loss of product occurring as a result of transfer to a truck or rail car or train derailments;
leakage or loss of access to hydrocarbons resulting from formations with abnormal pressures and basin subsidence;
release of pollutants; and
spills, leaks or discharges of fluids used in or producedus in the course of operations, especially thosefuture at a price that reach surface water or groundwater.
Some of these risks or hazards could materially and adversely affect our revenues and expenses by reducing or shutting in production from wells, causing the loss of equipment or otherwise negatively impacting the projected economic performance of our projects.us. In addition, our ability to deliver product pursuant to long-term supply contracts could be negatively impacted, resulting in additional financial exposure in the event we cannot fully deliver the contract quantities.
Anylack of these risks or hazards can result in injuries and/or deaths of employees, supplier personnel or other individuals, loss of hydrocarbons, environmental pollution and other damage to our properties or the properties of others, regulatory investigations and administrative, civil and criminal penalties or restricted access to our properties.
In addition, our operations and financial results could be significantly impacted by adverse weather conditions and natural disasters in the areas we operate including:
hurricanes, tropical storms, windstorms, or “superstorms,” which could affect our operations in areas such as Texas;
winter storms and snow, which could affect our operations in the DJ Basin;
extremely high temperatures, which could affect our midstream or third-party gathering and processing facilities in the DJ Basin and Texas;
severe droughts, which could result in new restrictions on water usage in the DJ Basin and Texas;
harsh weather and rough seas offshore international locations, which could limit exploration activities; and
other natural disasters.
Any of these can result in loss of hydrocarbons, environmental pollution and other damage to our properties or the properties of others, or restricted access to our properties.
Development drilling may not result in commercially productive quantities of crude oil and natural gas reserves from unconventional or conventional resources.
We depend on development projects to provide sustained cash flows after investment and attractive financial returns. However, development drilling is not always successful and the profitability of development projects may change over time.
In new development areas, including certain shale formations, available data may not allow us to completely know the extent of the reservoir or the best locations for drilling development wells. Therefore, a development well we drill, or in which we participate, may be a dry hole, may result in noncommercial quantities of hydrocarbons or may be less productive than our initial estimates.
We expect to invest significant amounts of capital to continue development of our US onshore unconventional resources and to progress the development of the Leviathan field project. In unconventional basins, development is highly dependent on costs of equipment and services, the use of technologies to drive capital and cost efficiencies in drilling and completion, and the availability of, or capacity on, third-party systems and access to midstream infrastructure. Even if development drilling is successful and we find commercial quantities of reserves, we may encounter difficultiesfacilities, including those owned by Noble Midstream Partners, could reduce the price offered for our production or delays in completing development wells. For example, frontier areas or less developed onshore areas may not have adequate infrastructure for gathering, transportation or processing, and production may be delayed until such infrastructure is constructed.
Exploratory drilling subjects us to risks and may not result in the discoveryshut-in of commercially productive reservoirs.
Exploratory drilling requires significant capital investment and does not always result in commercial quantitiesproducing wells or the delay or discontinuance of hydrocarbons or new development projects. In addition, exploratory drilling activities may be curtailed, delayed or canceled, or development plans may change, resulting in significant exploration expense, as a resultfor properties. Further, the inability of a variety of factors, including unexpected drilling conditions and pressure or other irregularities in formations. Furthermore, remote locations may make it more difficult and time-consuming to transport personnel, equipment and supplies, and we may face more difficult environments, such as oil sands, deepwater, or ultra-deepwater, in our efforts to seek new reserves, and may need to develop or invest in new technologies. These operating environments, and potential for harsh weather, increase cost as well as drilling risk.
Exploratory dry holes can occur because seismic data and other technologies we use to determine potential exploratory drilling locations do not allow us to know conclusively prior to drilling a well that crude oil or natural gas is present or may be produced economically. In addition, a well may be successful in locating hydrocarbons, but we and our partners may decide not to develop the prospect due to other considerations.
In addition, for certain capital-intensive offshore projects, it may take several years to evaluate the future potential of an exploratory well and make a determination of its economic viability, resulting in delays in cash flows from production start-up and a lower return on our investment.
We hold working interests in certain areas, including offshore areas of Cyprus, Cameroon, Gabon and Newfoundland (Canada) where there is minimal or no crude oil, NGL or natural gas production, and in certain cases, limited infrastructure. If commercial quantities of hydrocarbons are discovered, areas with minimal or no current production must begin to address topics such as sector regulation and distribution of government proceeds from hydrocarbon sales, the results of which could
Failure to adequately fund continued capital expenditures could adversely affect our properties.
Our exploration, development, and acquisition activities require capital expenditures to achieve production and cash flows. In particular, major offshore projects have a multi-year long development cycle time, which means that development spending occurs for several years before the project begins producing hydrocarbons and generating cash flows. As examples, assets and infrastructure for export of natural gas from Leviathan require a multi-billion dollar investment prior to production startup. Furthermore, while our DJ Basin assets are primarily held by production, other assets, such as our Eagle Ford Shale and Delaware Basin properties, are held primarily through continuous development obligations. Therefore, we are contractually obligated to fund a level of development activity in these areas, the amount of which could be substantial, or exercise options with land owners to extend leases. Failure to meet continuous development obligations or to exercise lease extensions may result in loss of leases.
Historically, we have funded our capital expenditures through a combination of cash flows from operations, our Revolving Credit Facility (defined below), debt and equity issuances, and occasional sales of assets. Future cash flows from operations are subject to a number of variables, as enumerated herein. If commodity prices decline for an extended period of time, we will evaluate our level of capital spending and likely reduce our investment program. As a result, we will have less ability to replace our reserves through drilling operations and may elect to forfeit our ownership interests or rights to participate in some properties, resulting in lower productionthird-party processors, over time as compared with prior years. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Operating Outlook – 2019 Capital Investment Program.Our Midstream reportable segment derives a substantial portion of its revenue from unaffiliated, third party customers. If any of these customers changes its business strategy, alters current drilling and development plans on dedicated acreage, or otherwise significantly reduces the volumes of crude oil, natural gas, produced water or fresh water with respect to which we perform midstream services, our Midstream revenues would decline and have negative impacts on our business, financial condition, results of operations, and cash flows.
We have numerous commercial agreements to provide midstream services and crude oil sales for unaffiliated third-party customers, some of whom are non-investment grade. Accordingly, because we derive a substantial portion of our midstream revenue from these commercial agreements, we are subject to the operational and business risks of these customers, the most significant of which include the following:
a reduction in or slowing of customer drilling and development plans on our dedicated acreage, which would directly and adversely impact demand for our midstream services;
the volatility of crude oil, natural gas and NGL prices, which could have a negative effect on our customers’ drilling and development plans on our dedicated acreage or ability to finance their operations and drilling and completion costs on our dedicated acreage;
the availability of capital on an economic basis for our customers to fund their exploration and development activities;
drilling and operating risks associated with customer operations on our dedicated acreage;
downstream processing and transportation capacity constraints and interruptions, including the failure of our customers to have sufficient contracted processing or transportation capacity; and
adverse effects of increased or changed governmental and environmental regulation or enforcement of existing regulation.
Further, we have no control, to meet anticipated facility expansion deadlines, or to delay or even cancel projects, in areas where our production is growing, could result in curtailment of our production growth and/or shut-in of production. Even where we have some contractual control over the transportation of our customers’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 or geopolitical instability.
Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities, could delay or curtail production, thereby harming our business decisions and, in turn, our results of operations, cash flows, and our customers are under no obligation to adopt a business strategy that is favorable to us. Thus, we are subject to the risk of cancellation of planned development, breach of commitments with respect to future dedications, and other non-payment or non-performance by our customers, including with respect to our commercial agreements, which do not contain minimum volume commitments.financial condition.
Our ability to produce crude oil, NGLs 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 and development activities require the use of water and results in the production of waste water. For example, the hydraulic fracturing process, which we employ to produce commercial quantities of crude oil, NGLs and natural gas from many reservoirs, requires the use and disposal of significant quantities of water. In certain regions, there may be insufficient local capacity to provide a source of water for drilling activities. In those cases, water must be obtained from other sources and transported to the drilling site, adding to the development cost. Waste water from oil and gas operations often is disposed of via underground injection. Some studies have linked earthquakes or induced seismicity in certain areas to underground injection, which is leadinghas led to increased public scrutiny of injection safety.
The development of new environmental initiatives or regulations related to acquisition, withdrawal, storage and use of surface water or groundwater, or treatment and discharge of water waste, may limit our ability to use techniques such as hydraulic fracturing, increase our development and operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted and all of which could have an adverse effect on our operations and financial condition. See Federal, state and local hydraulic fracturing and water disposal legislation and regulation could increase our costs or restrict our ability to produce crude oil, NGLs and natural gas economically and in commercial quantities and Items 1. and 2. Business and Properties – Hydraulic Fracturing. A negative shift in investor or shareholder sentiment of the oil and gas industry could adversely affect our business and ability to raise debt and equity capital.
Certain segments of the investor community have developed negative sentiment towards investing in our industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. In addition, some investors, including investment advisors and certain sovereign wealth, pension funds, university endowments and family foundations, have stated policies to disinvest in the oil and gas sector based on their social and environmental considerations. Certain other stakeholders have also pressured commercial and investment banks to reduce or stop financing oil and gas and related infrastructure projects.
In addition, shareholder activism has been recently increasing in our industry, and shareholders may attempt to effect changes to our business or governance, whether by shareholder proposals, public campaigns, proxy solicitations or otherwise. Such actions could adversely impact our business by distracting management and other personnel from their primary responsibilities, require us to incur increased costs, and/or result in reputational harm.
Such developments, including environmental activism and initiatives aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of oil and gas companies, including ours. This may also potentially result in a reduction of available capital funding for potential development projects, impacting our future financial results.
We face various risks associated with globalGlobal populism and general political uncertainty.uncertainty could adversely effect on our business, financial condition and results of operations.
Following the 2008/2009 global financial crisis, the world has experienced lower economic growth versus the levels attained in previous decades. Recent trade tensions and tariff disputes, including retaliation to such policies which have the potential to escalate into global trade wars, have also contributed to a slowing of global trade activities further compounding concerns around jobs, economic well-being and wealth distribution. Globally, certain individuals and organizations are attempting to focus the public's attention on income and wealth distribution and implement income and wealth redistribution policies.
Recent events have intensified these risks. Globally, and in the US, the growing trends toward populism and political polarization have resulted in uncertainty regarding potential changes in regulations, fiscal policy, social programs, domestic and foreign relations and international trade policies and tariffs.
Changes in relationships among the US, China, Russia and Russia,Saudi Arabia, and/or among China, Russia, Saudi Arabia and other countries, have potentially significant impacts on the global balance of power, as well as on global trade, with resultant impacts on both global and local economies. In addition, changes in the relationship between the US and its neighbors is currently impactingcontinues to impact commerce and trade across the North American continent. In Europe, the populist movement has resulted in the Brexit vote and increasing populist demands coupled with rising nationalism could have a negative impact on economic policy and consequently pose a potential threat to economic growth as well as the unity of the European Union.
Trade and/or tariff disputes could result in increased costs or shortages of materials and supplies, such as steel products and aluminum, which the oil and gas industry relies on to produce, process and transport its oil and gas production. Our ability to respond to these developments or comply with any resulting new legal or regulatory requirements, including those involving economic and trade sanctions, could reduce our ability to negotiate the sale of our products, increase our costs of doing business, reduce our financial flexibility and otherwise have a material adverse effect on our business, financial condition and results of our operations.
Indebtedness may limit our liquidity and financial flexibility.
At December 31, 2018,2019, we had $6.6$7.5 billion of consolidated debt, of which $560 million relates to$1.5 billion is issued by Noble Midstream Partners, and indebtedness represented 39% of our total book capitalization (sum of debt plus shareholders' equity).Partners.
Indebtedness affects our operations in several ways, including the following:following, among others:
a portion of our cash flows from operating activities must be used to service our indebtedness and is not available for other purposes;
we may be at a competitive disadvantage as compared to similar companies that have less debt;
a covenant contained in our Credit Agreement provides that our total debt to capitalization ratio (as defined in the Credit Agreement) may not exceed 65% at any time, which may make additional borrowings more expensive, thereby affecting our flexibility in planning for, and reacting to, changes in the economy and our industry;
additional future financing for working capital, capital expenditures, acquisitions, general corporate or other purposes may have higher costs and more restrictive covenants; and
we may be more vulnerable to general adverse economic and industry conditions.
We may incur additional debt in order to fund our exploration, development, acquisition and acquisitionmidstream activities. A higher level of indebtedness increases the risk that our financial flexibility may deteriorate. Our ability to meet our debt obligations and service
our debt depends on future performance. General economic conditions, commodity prices, and financial, business and other factors may 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.
In addition, a downgrade or other negative rating action could affect our requirements to post collateral as financial assurance of performance under certain contractual arrangements, such as pipeline transportation contracts, crude oil and natural gas sales contracts, work commitments and certain abandonment obligations. A lowering of our debt credit rating may negatively affect the cost, terms, conditions and/or availability of future financing, including access to the commercial paper market, and lower ratings will increase the interest rate and fees we pay on our Revolving Credit Facility.Facility, including our commercial paper program. These actions, in turn, could result in negative impacts on our business, financial condition and liquidity. See Item 8. Financial Statements and Supplementary Data – Note 9.8. Long-Term Debt. We face significant competition and many of our competitors have resources in excess of our available resources.
We operate in highly competitive areas of crude oil and natural gas exploration, development, acquisition and production. We face intense competition from various types of competitors ranging from large multi-national, integrated oil and gas companies, to state-controlled national oil companies, to independent oil and gas companies, to privately backed oil and gas equity funds, to name a few.
We also face competition in a number of areas such as:
as acquiring desirable producing properties or new leases for future exploration;
exploration, acquiring or increasing access to gathering, transportation and processing services and capacity;
capacity and in the marketing of our crude oil, NGL and natural gas production;production.
acquiringIn addition, we also compete for access to third-party oilfield equipment, materials, services and personnel required to explore, develop and operate properties. During periods of increasing levels of industry activity, the equipmentdemand for, and expertise necessary to operatecost of, drilling rigs and develop properties;oilfield services increases. As a result, drilling rigs and
attracting and retaining employees with certain skills. oilfield services may not be available at rates that provide a satisfactory return on our investment.
Many of our competitors have financial and other resources substantially in excess of those available to us. Such companies may be able to pay more for seismic information and lease rights on crude oil and natural gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. This highly competitive environment could have an adverse impact on our business. See Items 1. and 2. Business and Properties – Competition. Estimates of crudeCrude oil, NGL and natural gas reserves are not precise.estimates and actual recoveries may vary significantly.
Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, NGLs and natural gas that cannot be measured in an exact manner, and there are numerous uncertainties inherent in estimating reserves quantities and their value, including factors that are beyond our control.
In accordance with the SEC's rules for oil and gas reserves reporting, our reserves estimates are based on historical 12-month average commodity prices; therefore, reserves quantities will change when actual prices increase or decrease. As estimated production, development and abandonment costs are based on year-endyear end economic conditions, reserves quantities will also change when these costs increase or decrease.
Reserves estimates depend on a number of factors and assumptions that may vary considerably from actual results, including:
estimating future production from an area is consistent with historical production from the area compared with production from othersimilar producing areas;
assumed effects of regulations by governmental agencies, including the SEC;
anticipated development cycle time;
future development, costs;
future operating and abandonment costs;costs, as well as timing of such activities; and
impacts of cost recovery provisions in contracts with foreign governments;
severance and excise taxes; and
workover and remedial costs.governments.
For these reasons, estimates of the economically recoverable quantities of crude oil, NGLs 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, NGL and natural gas reserves in emerging areas or areas with limited historical production is inherently more difficult, and we may have less experience in such areas. Accordingly, reserves estimates may be subject to positive or negative revisions, and actual production, revenues and expenditures with respect to our reserves likely will vary, possibly materially, from estimates. Any such negative revisionsA decline in estimates of proved reserves could result in an asset impairment charge.
Additionally, some of our reserves estimates are calculated using volumetric analysis, which involves estimating the volume of a reservoir based on the net feet of pay of the structure and an estimation of the area covered by the structure. Reserves estimates using volumetric analysis are less reliable than estimates based on a lengthy production history.
We operate in a litigious environment.
Some of the jurisdictions within which we operate have proven to be litigious environments. Oil and gas companies can be involved in various legal proceedings and disputes with landowners, royalty owners, or other operators over matters such as leases, title transfer, joint interest billing arrangements, revenue distribution, or production or cost sharing arrangements, in the ordinary course of business. For example, in certain states, oil and gas companies are often the target of “legacy lawsuits,” by which a landowner claims that oil and gas operations, often performed many years ago and by another operator, caused pollution or contamination of a property. Various properties we have owned over the past decades potentially expose us to “legacy lawsuit” claims. Similarly, neighboring landowners may allege that current operations cause contamination or create a nuisance.
Because we maintain a diversified portfolio of assets that includes both US and international projects, the complexity and types of legal procedures with which we may become involved may vary, and we could incur significant legal and support expenses in different jurisdictions. For example, we historically have had to address certain fiscal, antitrust and other regulatory
challenges in Israel, including a current lawsuit filed by petitioners alleging we and our partners in Tamar violated antitrust laws through the monopolistic pricing of natural gas to the citizens of Israel. Legal proceedings such as this could result in substantial liability and/or negative publicity about us and adversely affect the price of our common stock. In addition, legal proceedings distract management and other personnel from their primary responsibilities. These proceedings are subject to the uncertainties inherent in any litigation. We will defend ourselves vigorously in all such matters. However, if we are not able to successfully defend ourselves, there could be a delay or even a halt in our exploration, development or production activities or other business plans, resulting in a reduction in reserves, loss of production and reduced cash flows.
One of our subsidiaries acts as the general partner of a publicly traded master limited partnership, Noble Midstream Partners, which may involve a potential legal liability.
One of our subsidiaries acts as the general partner of Noble Midstream Partners, a publicly traded master limited partnership. Our control of the general partner of Noble Midstream Partners may increase the possibility that we could be subject to claims of breach of fiduciary duties owed to Noble Midstream Partners, including claims of conflicts of interest, related to Noble Midstream Partners.interest. Any liability resulting from such claims could have a material adverse effect on our future business, financial condition, results of operations and cash flows.
We may be subject to risks in connection with acquisition and divestiture activities.
As part of our business strategy, we have made, and will likely continue to make, acquisitions of oil and gas properties and/or entities that own them. If we are unable to make attractive acquisitions, our future growth could be limited. Moreover, even if we do make acquisitions, they may not result in an increase in our cash flows from operations or otherwise result in the benefits anticipated due to various risks, including, but not limited to:
incorrect estimates or assumptions about reserves, exploration potential or potential drilling locations;
incorrect assumptions regarding future revenues, including future commodity prices and differentials, or regarding future development and operating costs;
incorrect assumptions regarding potential synergies and the overall costs of equity or debt;
difficulties in integrating the operations, technologies, products and personnel of the acquired assets or business; and
unknown and unforeseen liabilities or other issues related to any acquisition for which contractual protections prove inadequate, including environmental liabilities and title defects.
Mergers of businesses often require the approval of certain government or regulatory agencies and such approval could contain terms, conditions, or restrictions that would be detrimental to our business after a merger. US antitrust laws require waiting periods and even after completion of a merger, governmental authorities could seek to block or challenge a merger as they deem necessary or desirable in the public interest. We have merged with or acquired other companies in the past. Prevention of a merger by antitrust laws could impair our ability to do business. Furthermore, mergers and acquisitions expose us to potential lawsuits or other obligations not yet anticipated at time of merger or acquisition. Such liabilities and obligations could hinder our ability to fully benefit from the acquired business or assets and negatively impact our financial performance.
The acquisition of a property or business requires management to make complex judgments and assessments, and the accuracy of the assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties
that we believe to be consistent with industry practices. Our review will not reveal all existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities.
We also maintain an ongoing portfolio management program to ensure our company is well-positioned with assets that offer growth at financially attractive investment options. Therefore, we may periodically divest certain material assets. We strive to obtain the most attractive prices for our assets; however, various factors can materially affect our ability to dispose of assets on terms acceptable to us. Such factors may include:
current commodity prices;
laws and regulations impacting oil and gas operations in the areas where the assets are located;
willingness of the purchaser to assume certain liabilities such as asset retirement obligations;
our willingness to indemnify buyers for certain matters; and
delays in closing.
Inability to achieve a desired price for the assets, or underestimation of amounts of retained liabilities or indemnification obligations, can result in a reduction of cash proceeds, a loss on sale due to an excess of the asset's net book value over proceeds, or liabilities which must be settled in the future at amounts that are higher than we anticipated. In addition, although we may successfully divest oil and gas assets, we may retain certain related contracts. For example, although we sold our Marcellus Shale upstream properties in 2017, we retained significant obligations under firm transportation contracts. Our inability to fully commercialize these contracts and reduce the associated financial commitments could result in a decrease in cash flows from operations. In addition, we may be required to recognize losses in accordance with exit or disposal activities. See Item 7. Management's Discussion of Financial Condition and Results of Operations – Liquidity and Capital Resources – Contractual Obligations.We are exposed to counterparty credit risk as a result of our receivables, hedging transactions and cash investments.
We are exposed to risk of financial loss from joint venture and other receivables. We are the operator on a majority of our joint venture development projects, including Leviathan. As joint venture operator, we pay joint venture expenses and make cash calls on nonoperating partners for their respective shares of joint venture costs. These projects are capital intensive and, in some cases, a nonoperating partner may experience a delay in obtaining financing for its share of the joint venture costs or have liquidity problems resulting in slow payment of joint venture costs that can result in potential delays in our development projects. In addition, some of our joint venture partners are not as creditworthy as we are and may experience credit rating downgrades or liquidity problems that may hinder their ability to obtain financing. Counterparty liquidity problems could result in a delay in receiving proceeds from reimbursement of joint venture costs. Nonperformance by a joint venture partner could result in significant financial losses.
We have cash and cash equivalents deposited with financial institutions, a majority of which is invested in money market funds and short-term deposits with major financial institutions. In addition, our hedging activities may expose us to counterparty credit risk or, in some cases, cause us to incur significant cash settlements. As an entity entering into derivatives transactions under master agreements that are subject to US laws, we are subject to some limitations on our ability to exercise default rights with respect to derivatives transactions with a financially-troubled bank. On January 1, 2019, the US Bank Regulators imposed additional restrictions on counterparties that are parties to certain types of Qualified Financial Contracts (QFCs) with major banks that have been designated as Global Systemically Important Banks (G-SIBs). These QFCs include various master agreements and the financial derivatives transactions that are entered into under such master agreements with G-SIBs as counterparties.
While we monitor the creditworthiness of joint venture partners, purchasers, banks and financial institutions with which we conduct business, we are unable to predict sudden changes in solvency of these counterparties and may be exposed to associated risks. Credit enhancements have been obtained from some parties in the form of parental guarantees, letters of credit or credit insurance; however, not all of our counterparty credit is protected through guarantees or credit support. In addition, we maintain credit insurance associated with specific purchasers. However, nonperformance by a hedge counterparty or financial institution could result in significant financial losses.
Commodity hedging transactions may limit our potential gains or fail to fully protect us from declines in commodity prices.
In order to reduce the impact of commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas,production, we enter into hedging arrangements with respect to a portion of our expected revenues. Our hedges, consisting of a series of derivative instrument contracts, are limited in duration, usually for periods of one to three years. While intended to reduce the effects of volatile crude oil and natural gascommodity prices, such transactions may limit our potential gains if prices rise over the price established by the arrangements. Conversely, our hedging program may be inadequate to protect us from continuing and prolonged declines in the price of crude oil or natural gas.commodity prices. See Item 8. Financial Statements and Supplementary Data – Note 13.14. Derivative Instruments and Hedging Activities. The insurance we carry is insufficient to cover all of the risks we face, which could result in significant financial exposure.
Exploration for and production of crude oil and natural gas can be hazardous, involving natural disasters or other catastrophic events such as hurricanes, earthquakes, blowouts, well cratering, fire and explosion, loss of well control, gathering system or pipeline disruptions, mishandling of fluids and chemicals, and possible underground migration of hydrocarbons and chemicals, any of which can result in damage to or destruction of wells or formations or production facilities, injury to persons, loss of life, or damage to property and the environment. Exploration and production activities are also subject to risk from other disruptive events such as terrorist acts, piracy, civil disturbances, war, and expropriation or nationalization of assets, or other interruptions, such as cyber security breaches, which can cause loss of or damage to our property.
Our insurance program and memberships in domestic and international dedicated oil spill and emergency response organizations may not minimize or fully protect us from losses resulting from damages to or the loss of physical assets or loss of human life, liability claims of third parties, and business interruption (loss of production) attributed to certain assets and including such occurrences as well blowouts and resulting oil spills. We do not have insurance protection against all the risks we face, because we choose not to insure certain risks, insurance is not available at a level that balances the cost of insurance and our desired rates of return, or actual losses may exceed coverage limits.
We expect the futureFuture availability and cost of insurance tocan be impacted by events such as hurricanes, earthquakes and other natural disasters. Impacts could include tighter underwriting standards, limitations on scope and amount of coverage, and higher premiums, and will depend, in part, on future changes in laws and regulations regarding exploration and production activities in areas in which we operate, including possible increases in liability caps for claims of damages from oil spills. We will continue to monitor for any legislative or regulatory changes relatedrelating to exploration and production and its potential impact on the insurance market and our overall risk profile, and adjust our risk and insurance program to provide protection, at a level that we can afford considering the cost of insurance and our desired rates of return, against disruption to our operations and cash flows.
If an event, for example, a major offshore incident resulting in significant personal injury and/or environmental and physical damage, occurs that is not covered by insurance or not fully protected by insured limits, it could have a significant adverse impact on our financial condition, results of operations and cash flows. See Items 1. and 2. Business and Properties – Risk and Insurance Program. Item1B. Unresolved Staff Comments
None.
Item 3. Legal Proceedings
We are involved in various legal proceedings in the ordinary course of business. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters and we believe that the
Item 4. Mine Safety Disclosures
Not Applicable.
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Common Stock On December 16, 2019, acting pursuant to authorization from our Board of Directors, we provided notice to the New York Stock Exchange (NYSE) of our intent to voluntarily withdraw the principal listing of our common stock, par value $0.01 per share, from the NYSE and transfer the listing to Nasdaq. Our common stock $0.01 par value, is listed and tradedwas voluntarily delisted on the NYSE effective as of the close of trading on December 27, 2019, and trading commenced on Nasdaq at market open on December 30, 2019. Our stock continues to trade under the stock symbol “NBL.”
DividendsThe declaration and payment of dividends are determined on a quarterly basis and 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.
Dividends On January 29, 2019,27, 2020, our Board of Directors declared a quarterly cash dividend of $0.11$0.12 per common share. The dividend will be paid February 25, 2019,24, 2020, to shareholders of record on February 11, 2019.10, 2020. See Item 8. Financial Statements and Supplementary Data – Consolidated Statements of Shareholders' Equity.Transfer Agent and Registrar The transfer agent and registrar for our common stock is Computershare Trust Company N.A., 250 Royall Street, Canton, MA, 02021.
Shareholders’ Profile Pursuant to the records of the transfer agent, as of February 7, 2019,4, 2020, the number of holders of record of our common stock was 541.522.
Stock Repurchases The following table summarizes repurchases of our common stock occurring in fourth quarter 2018:2019: |
| | | | | | | | | | | | | | |
| 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) |
| 10/1/2018 - 10/31/2018 | | 59,006 |
| | $ | 29.37 |
| | — |
| | |
| 11/1/2018 - 11/30/2018 | | 1,630,968 |
| | 24.57 |
| | 1,621,076 |
| | |
| 12/1/2018 - 12/31/2018 | | 964,927 |
| | 23.53 |
| | 964,609 |
| | |
| Total | | 2,654,901 |
| | $ | 24.29 |
| | 2,585,685 |
| | $ | 455 |
|
|
| | | | | | | | | | | | | |
| 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) |
| 10/1/2019 - 10/31/2019 | 3,060 |
| | $ | 20.07 |
| | — |
| | |
| 11/1/2019 - 11/30/2019 | 125 |
| | 21.24 |
| | — |
| | |
| 12/1/2019 - 12/31/2019 | 81 |
| | 20.91 |
| | — |
| | |
| Total | 3,266 |
| | $ | 20.14 |
| | — |
| | $ | 455 |
|
(1) Includes stock repurchases of 69,216 shares during the period related to 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 fourth quarter 2018, we repurchased and retired 2,585,685 shares of common stock at an average purchase price of $24.19 per share pursuant to the $750 million share repurchase program, authorized by the Board of Directors and announced in February 2018, which expires on December 31, 2020. | |
(1) | Shares repurchased during the period related to 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 fourth quarter 2019, we did not repurchase any shares under the $750 million share repurchase program, authorized by the Board of Directors and announced in February 2018, which expires on December 31, 2020. |
Stock Performance Graph On January 28, 2019, the Compensation, Benefits and Stock Option Committee of the Board of Directors (the Committee) made changes to our compensation peer group to accurately reflect, in the judgment of the Committee, companies with which we compete for investment capital and market recognition. Criteria used to determine this new group included similarity of long-term business strategy, multi-basin operations, commodity mix and international presence. After the change in companies, the new peer group consisted of the following:
|
| | |
Anadarko Petroleum Corp. (1) | Devon Energy Corp. | Murphy Oil Corp. |
| Apache Corp. | Ovintiv Inc. (formerly known as Encana Corp.) | Noble Energy, Inc. |
| Chesapeake Energy Corp. | EOG Resources, Inc. | WPX Energy, Inc. |
| Cimarex Energy Co. | Hess Corp. | |
| Continental Resources, Inc. | Marathon Oil Corp. | |
| |
(1) | Anadarko Petroleum Corp. is excluded from all periods in the graph below due to its acquisition by Occidental Petroleum Corp. in 2019. |
Compared to our 2018 peers, the new 2019 peer group includes Cimarex Energy Co., Encana Corp. and WPX Energy, Inc., and excludes Cabot Oil & Gas Corp., Pioneer Natural Resource Co., Range Resources Corp. and Southwestern Energy Co.
This graph shows our cumulative total shareholder return over the five-year period from December 31, 20132014 to December 31, 2018.2019. The graph also shows the cumulative total returns for the same five-year period of the S&P 500 Index, and athe previous peer group of companies.used in 2018, and the new 2019 peer group. The cumulative total return of the common stock of our 2018 and 2019 peer group of companiesgroups includes the cumulative total return of our common stock.
Our peer group includes a broad group of US onshore and global exploration and production companies which are further diversified by location and number of resource plays as well as level of integration within the crude oil and natural gas business cycle. Our peer group consists of the following:
|
| | |
Anadarko Petroleum Corp. | Devon Energy Corp. | Noble Energy, Inc. |
Apache Corp. | EOG Resources, Inc. | Pioneer Natural Resources Co. |
Cabot Oil & Gas Corp. | Hess Corp. | Range Resources Corp. |
Chesapeake Energy Corp. | Marathon Oil Corp. | Southwestern Energy Co. |
Continental Resources, Inc. | Murphy Oil Corp. | |
The comparison assumes $100 was invested on December 31, 20132014 in our common stock, in the S&P 500 Index and in our 2019 and 2018 peer group of companiesgroups and assumes that all of the dividends were reinvested. In addition, theeach peer group investment is weighted based upon the market capitalization of each individual company within the applicable peer group.
Copyright© 2020 Standard & Poor's, a division of S&P Global. All rights reserved.
|
| | | | | | | | | | | | | | | |
| Year Ended December 31, | 2015 | 2016 | 2017 | 2018 | 2019 |
| Noble Energy, Inc. | $ | 70.66 |
| $ | 82.62 |
| $ | 64.10 |
| $ | 41.88 |
| $ | 56.66 |
|
| S&P 500 | 101.38 |
| 113.51 |
| 138.29 |
| 132.23 |
| 173.86 |
|
| 2018 (Previous) Peer Group | 61.58 |
| 90.75 |
| 83.75 |
| 62.94 |
| 65.16 |
|
| 2019 (New) Peer Group | 61.28 |
| 94.22 |
| 88.70 |
| 63.73 |
| 66.02 |
|
|
| | | | | | | | | | | | | | | |
| Year Ended December 31, | 2014 | 2015 | 2016 | 2017 | 2018 |
| Noble Energy, Inc. | $ | 70.38 |
| $ | 49.73 |
| $ | 58.15 |
| $ | 45.11 |
| $ | 29.47 |
|
| S&P 500 | 113.69 |
| 115.26 |
| 129.05 |
| 157.22 |
| 150.33 |
|
| Peer Group | 86.06 |
| 53.24 |
| 76.93 |
| 68.75 |
| 51.93 |
|
Item 6. Selected Financial Data | | | | | Year Ended December 31, | Year Ended December 31, |
| (millions, except as noted) | | 2018 | | 2017 | | 2016 | | 2015 | | 2014 | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| Revenues and Income | | | | | | | | | | | | | | | | | | | |
| Total Revenues | | $ | 4,986 |
| | $ | 4,256 |
| | $ | 3,491 |
| | $ | 3,183 |
| | $ | 5,115 |
| $ | 4,438 |
| | $ | 4,986 |
| | $ | 4,256 |
| | $ | 3,491 |
| | $ | 3,183 |
|
| Net Income (Loss) and Comprehensive Income (Loss) Including Noncontrolling Interests | | 14 |
| | (1,050 | ) | | (985 | ) | | (2,441 | ) | | 1,214 |
| |
| Net (Loss) Income and Comprehensive (Loss) Income Attributable to Noble Energy | | (66 | ) | | (1,118 | ) | | (998 | ) | | (2,441 | ) | | 1,214 |
| |
Asset Impairments (1) | | 1,160 |
| | 206 |
| | 70 |
| | 92 |
| | 533 |
|
| Net (Loss) Income and Comprehensive (Loss) Income Including Noncontrolling Interests | | (1,433 | ) | | 14 |
| | (1,050 | ) | | (985 | ) | | (2,441 | ) |
| Net Loss and Comprehensive Loss Attributable to Noble Energy | | (1,512 | ) | | (66 | ) | | (1,118 | ) | | (998 | ) | | (2,441 | ) |
| Per Share Data, Attributable to Noble Energy | | | | |
| | | | |
| | |
| | | |
| | | | |
| | |
|
| (Loss) Earnings Per Share - Basic | | (0.14 | ) | | (2.38 | ) | | (2.32 | ) | | (6.07 | ) | | 3.36 |
| |
| (Loss) Earnings Per Share - Diluted | | (0.14 | ) | | (2.38 | ) | | (2.32 | ) | | (6.07 | ) | | 3.27 |
| |
| Cash Dividends Per Share | | 0.43 |
| | 0.40 |
| | 0.40 |
| | 0.72 |
| | 0.68 |
| |
| Year-End Stock Price Per Share | | 18.76 |
| | 29.14 |
| | 38.06 |
| | 32.93 |
| | 47.43 |
| |
| Loss per Share - Basic and Diluted | | $ | (3.16 | ) | | $ | (0.14 | ) | | $ | (2.38 | ) | | $ | (2.32 | ) | | $ | (6.07 | ) |
| Cash Dividends per Share | | 0.47 |
| | 0.43 |
| | 0.40 |
| | 0.40 |
| | 0.72 |
|
| Stock Price per Share | | 24.84 |
| | 18.76 |
| | 29.14 |
| | 38.06 |
| | 32.93 |
|
| Weighted Average Number of Shares Outstanding | | | | |
| | |
| | |
| | |
| | | |
| | |
| | |
| | |
|
| Basic | | 483 |
| | 469 |
| | 430 |
| | 402 |
| | 361 |
| |
| Diluted | | 483 |
| | 469 |
| | 430 |
| | 402 |
| | 367 |
| |
| Basic and Diluted | | 478 |
| | 483 |
| | 469 |
| | 430 |
| | 402 |
|
| Cash Flows | | | | |
| | |
| | |
| | |
| | | |
| | |
| | |
| | |
|
| Net Cash Provided by Operating Activities | | $ | 2,336 |
| | $ | 1,951 |
| | $ | 1,351 |
| | $ | 2,062 |
| | $ | 3,506 |
| $ | 1,998 |
| | $ | 2,336 |
| | $ | 1,951 |
| | $ | 1,351 |
| | $ | 2,062 |
|
| Additions to Property, Plant and Equipment | | 3,279 |
| | 2,649 |
| | 1,541 |
| | 2,979 |
| | 4,871 |
| 2,524 |
| | 3,279 |
| | 2,649 |
| | 1,541 |
| | 2,979 |
|
Proceeds from Divestitures (1) | | 1,999 |
| | 2,073 |
| | 1,241 |
| | 151 |
| | 321 |
| |
Net Proceeds from Divestitures (2) | | 173 |
| | 1,999 |
| | 2,073 |
| | 1,241 |
| | 151 |
|
| Proceeds from Issuance of Noble Energy Common Stock, Net of Offering Costs | | — |
| | — |
| | — |
| | 1,112 |
| | — |
| — |
| | — |
| | — |
| | — |
| | 1,112 |
|
| Proceeds from Issuance of Noble Midstream Partners Common Units, Net of Offering Costs | | — |
| | 312 |
| | 299 |
| | — |
| | — |
| 243 |
| | — |
| | 312 |
| | 299 |
| | — |
|
| Financial Position | | | | | | | | | | | | | | | | | | | |
| Cash and Cash Equivalents | | $ | 716 |
| | $ | 675 |
| | $ | 1,180 |
| | $ | 1,028 |
| | $ | 1,183 |
| $ | 484 |
| | $ | 716 |
| | $ | 675 |
| | $ | 1,180 |
| | $ | 1,028 |
|
| Property, Plant and Equipment, Net | | 18,419 |
| | 17,502 |
| | 18,548 |
| | 21,300 |
| | 18,143 |
| 17,451 |
| | 18,419 |
| | 17,502 |
| | 18,548 |
| | 21,300 |
|
Goodwill (2) | | 110 |
| | 1,310 |
| | — |
| | — |
| | 620 |
| |
Goodwill (1) | | 110 |
| | 110 |
| | 1,310 |
| | — |
| | — |
|
| Total Assets | | 21,010 |
| | 21,476 |
| | 21,011 |
| | 24,196 |
| | 22,518 |
| 20,647 |
| | 21,120 |
| | 21,476 |
| | 21,011 |
| | 24,196 |
|
| Long-term Obligations | | | | | | | | | | | | | | | | | | | |
| Long-Term Debt | | 6,574 |
| | 6,746 |
| | 7,011 |
| | 7,976 |
| | 6,068 |
| 7,477 |
| | 6,574 |
| | 6,746 |
| | 7,011 |
| | 7,976 |
|
| Deferred Income Taxes | | 1,061 |
| | 1,127 |
| | 1,819 |
| | 2,826 |
| | 2,516 |
| 662 |
| | 1,061 |
| | 1,127 |
| | 1,819 |
| | 2,826 |
|
| Asset Retirement Obligations, Noncurrent | | 762 |
| | 824 |
| | 775 |
| | 861 |
| | 670 |
| 730 |
| | 762 |
| | 824 |
| | 775 |
| | 861 |
|
| Other | | 403 |
| | 421 |
| | 328 |
| | 358 |
| | 417 |
| 648 |
| | 403 |
| | 421 |
| | 328 |
| | 358 |
|
| Total Equity | | 10,484 |
| | 10,619 |
| | 9,600 |
| | 10,370 |
| | 10,325 |
| |
| Mezzanine Equity | | 106 |
| | — |
| | — |
| | — |
| | — |
|
| Total Shareholders' Equity | | 9,055 |
| | 10,484 |
| | 10,619 |
| | 9,600 |
| | 10,370 |
|
| | | | | Year Ended December 31, | Year Ended December 31, |
| | | 2018 | | 2017 | | 2016 | | 2015 | | 2014 | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| Operations Information - Consolidated Operations | | | | |
| | |
| | |
| | |
| |
| Consolidated Operations Information | | | | |
| | |
| | |
| | |
|
| Consolidated Crude Oil Sales (MBbl/d) | | 130 |
| | 129 |
| | 125 |
| | 112 |
| | 103 |
| 133 |
| | 130 |
| | 129 |
| | 125 |
| | 112 |
|
| Average Realized Price ($/Bbl) | | $ | 62.01 |
| | $ | 49.73 |
| | $ | 40.39 |
| | $ | 45.00 |
| | $ | 91.58 |
| $ | 56.21 |
| | $ | 62.01 |
| | $ | 49.73 |
| | $ | 40.39 |
| | $ | 45.00 |
|
| Consolidated NGL Sales (MBbl/d) | | 62 |
| | 58 |
| | 54 |
| | 39 |
| | 23 |
| 68 |
| | 62 |
| | 58 |
| | 54 |
| | 39 |
|
| Average Realized Price ($/Bbl) | | $ | 25.88 |
| | $ | 23.40 |
| | $ | 14.92 |
| �� | $ | 13.91 |
| | $ | 33.75 |
| $ | 14.32 |
| | $ | 25.88 |
| | $ | 23.40 |
| | $ | 14.92 |
| | $ | 13.91 |
|
| Consolidated Natural Gas Sales (MMcf/d) | | 922 |
| | 1,118 |
| | 1,397 |
| | 1,187 |
| | 992 |
| 925 |
| | 922 |
| | 1,118 |
| | 1,397 |
| | 1,187 |
|
| Average Realized Price ($/Mcf) | | $ | 2.76 |
| | $ | 3.01 |
| | $ | 2.42 |
| | $ | 2.44 |
| | $ | 3.38 |
| $ | 2.41 |
| | $ | 2.76 |
| | $ | 3.01 |
| | $ | 2.42 |
| | $ | 2.44 |
|
| Proved Reserves | | | | |
| | |
| | |
| | |
| | | |
| | |
| | |
| | |
|
| Crude Oil and Condensate Reserves (MMBbls) | | 457 |
| | 457 |
| | 333 |
| | 307 |
| | 304 |
| 413 |
| | 457 |
| | 457 |
| | 333 |
| | 307 |
|
| NGL Reserves (MMBbls) | | 266 |
| | 229 |
| | 219 |
| | 189 |
| | 128 |
| 278 |
| | 266 |
| | 229 |
| | 219 |
| | 189 |
|
| Natural Gas Reserves (Bcf) | | 7,231 |
| | 7,680 |
| | 5,308 |
| | 5,549 |
| | 5,833 |
| 8,151 |
| | 7,231 |
| | 7,680 |
| | 5,308 |
| | 5,549 |
|
| Total Reserves (MMBoe) | | 1,929 |
| | 1,965 |
| | 1,437 |
| | 1,421 |
| | 1,404 |
| 2,050 |
| | 1,929 |
| | 1,965 |
| | 1,437 |
| | 1,421 |
|
| Number of Employees | | 2,330 |
| | 2,277 |
| | 2,274 |
| | 2,395 |
| | 2,735 |
| 2,282 |
| | 2,330 |
| | 2,277 |
| | 2,274 |
| | 2,395 |
|
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:
The accompanying consolidated financial statements, including the notes thereto, contain detailed information that should be read in conjunction with our MD&A.
EXECUTIVE SUMMARY
Noble Energy Key Metrics (metrics should be reviewedFor discussion related to changes in financial condition and results of operations for 2018 as compared with 2017, refer to Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2018 Form 10-K, which was filed with the context of additional information provided in the links below)
SEC on February 19, 2019.
EXECUTIVE OVERVIEW
Industry Outlook
Crude OilCommodity Prices The global oil and gas industry is cyclical, and commodity prices can be volatile. Global crude oil prices are volatile, driven by crude oil supply, which includes OPECOrganization of Petroleum Exporting Countries (OPEC) and non-OPEC producers, and global crude oil demand. Building on the prior year's price recovery and higher demand, crude oil prices trended upward for most of 2018, with Brent and WTI crude oil prices reaching a four-year high, in excess of $80 and $70 per barrel, respectively. However, in November 2018, prices suddenly plunged, with Brent and WTI prices falling to nearly $50 and $40 per barrel, respectively, as traders focused on supply economics combined with concerns of slowing global growth.
The outlook for 20192020 crude oil prices will continue to depend on supply and demand dynamics, as well as global geopolitical and security factors in crude oil-producing nations. Even ifProduction cuts by OPEC cuts production, US shale supply is expected to continue to grow due to capital investmentand geopolitical factors in anticipation of the addition of takeaway capacity easing recent bottlenecks, such as in the Delaware Basin. These factors, and the potentialcritical oil producing regions remain constructive for slower global growth and increasing global uncertainty, could suppress crude oil prices. However, a weakening of crude oil demand amid signs of a potential softening in the global economy could result in lower prices. In addition, the spread between WTIUS and Brent prices has been widening, resulting in comparatively lower prices for US production. However, reductions in industry investment, particularly for conventionalChina trade tensions threaten further damage to global trade and economic growth and, consequently, crude oil development, will, over time, contribute to production declines, potentially supporting higher prices.demand.
Natural Gas The US domestic natural gas market remains oversupplied as domestic production has continued to grow due to drilling efficiencies, higher incremental volumes of associated gas from oil wells and de-bottlenecking of transportation infrastructure. In contrast to crude oil supply curtailments, there has been little to offsetDespite record domestic LNG exports and high natural gas supply growth, which continuesfired electric generation, natural gas inventories are projected to outpace demand domestically.remain at or slightly above historical five-year averages. As a result, natural gas prices remained range-boundtraded within a narrow range in 2018,2019, with an expectation to continue as such in 2019, with2020. Natural gas price differentials increased in the DJ Basin, while differentials in the Delaware Basin continue to be wide despite additional pipeline capacity from the Delaware Basin to Corpus Christi, Texas. Additional Delaware Basin natural gas pipeline expansions are targeted for in-service in late 2020, which are expected to decrease these differentials.
US NGL prices at or near current or recent trading levels.are also suppressed amid increased production, high inventory levels, and downstream fractionation and export bottlenecks. As new processing and export facilities are brought online, NGL prices should benefit. During 2019, we added NGL commodity price hedges to our hedge portfolio.
Impact of Current Commodity PricesThe chart below shows the historical trendtrends in benchmark prices for WTI crude oil, Brent crude oil, Mont Belvieu composite NGLs, and US Henry Hub natural gas.
Our Eastern Mediterranean GSPAs generally provide for an initial base price subject to price indexation over the life of the contract and have a contractual floor, which provides some protection from price volatility.
During 2019, our activities were focused on positioning the Company for sustainable, long-term cash flows through the following initiatives:
DevelopmentImproving Cost StructureWe focused on strong operational execution and Operating Costs As commodity prices strengthened,cost control to improve our cost structure for current and future operations. We reduced capital spend, focusing on high-margin, high-return opportunities while emphasizing safety and protection of the demandenvironment. Capital efficiencies resulted in significantly lower well costs, driving overall capital spend nearly $240 million lower than expected for oilfield equipment, services and infrastructure, particularly inthe year. Unit production expenses were also driven lower than expected, primarily due to US onshore basins, began to rise, leading to cost inflationinitiatives.
Improving US Onshore Takeaway CapacityWe successfully leveraged significant pipeline expansion projects for the drilling, completionincreased flow assurance and operating of wells, and for the construction and/or access to necessary oil and gas infrastructure. As a result, during 2018 there was pressure on operating margins and capital efficiency in US onshore basins, including those in which we operate. With the recentimproved crude oil price decline from mid-2018 highs,netback prices. In the development and operating cost structure has begun to shift downward, andDJ Basin, we expect margin pressure will continueentered into 2019.
Takeaway Capacity With higher commodity prices and the resurgencea strategic relationship with Saddlehorn, acquiring additional capacity of US onshore drilling activity, demand increased for access to gathering facilities, transportation and/orlong-term takeaway pipelines due to growing production volumes.at lower cost. In the Delaware Basin, midstream suppliers are workingwe exercised options to construct new gathering, transportationacquire ownership interests in EPIC Y-Grade and processing facilities or to repurpose existing infrastructureEPIC Crude Holdings, and partnered in an effort to proactively outpace expected production growth. In this regard, we have secured near-term flow assurance and long-term out-of-basin takeaway fromthe formation of the Delaware BasinCrossing joint venture. Through these investments, we gained access to the Texas Gulf Coast with access to export markets. See Items 1. and 2. Business and Properties – US Onshore.Colorado Proposition #112 On November 6, 2018, a majoritypricing for certain of Colorado voters voted against Proposition #112, which, if passed, would have significantly limited, or in some cases prevented, the future development of crude oil and natural gas and demand for our midstream services in areas where we currently conduct operations.Delaware Basin
Initiativesproduction when the EPIC Y-Grade Pipeline began interim crude oil service. We continue to negotiate other pipeline contracts for lower cost arrangements.
Leviathan Phase I DevelopmentHaving commenced production from the Leviathan field on December 31, 2019, we are now ready for significant regional exports to begin. We expect Leviathan production and regional sales will result in a significant impact to our sustainable production profile, with material increases in sales volumes and cash flows in 2020.
Progressing Natural Gas Monetization Offshore West AfricaWe continue to focus on progressing natural gas monetization opportunities through development of a regional natural gas hub offshore West Africa. During the year, we sanctioned the Alen Gas Monetization project, which will result in low-cost access to additional reserves and our entry into the global LNG markets in 2021.
Advancing Exploration OpportunitiesAlthough we have been underwaymodified our exploration activity in the State of Coloradolow commodity price environment, we continue to regulate, limit or ban hydraulic fracturing or other facets of crude oil and natural gas exploration, development or operations for some time. We are monitoring the work of the State of Colorado General Assemblypursue opportunities that have low capital commitments, but which we perceive to create a framework for future oil and gas development in the State.
Concurrently, we are engaged in extensive public education and outreach efforts, with the goal of engaging and educating the public and communities about the economic and environmental benefits of safe and responsible crude oil and natural gas development.
Impact of Tariffs During 2018, the US Administration imposed import tariffs of 25% on steel products and 10% on aluminum products, as well as quantitative restrictions on imports of steel and/or aluminum products from various countries. The US oil and gas industry relies on steel for drilling and completion of new wells, as well as for facility production at refineries, petrochemical plants and pipelines. Implementation of these tariffs will likely increase prices for specialty and other products used in our industry. Tariffs and quantitative restrictions may cause disruption in the energy industry’s supply chain, resulting in delay or cessation of drilling efforts or postponement or cancellation of new inter- or intra-state pipeline projects that the industry is relying on to transport its increasing onshore production to market, as well as endangering US LNG export projects resulting in negative impacts on natural gas pricing and production.
Recent Activities
have potentially high impact. During the period 2015-2018,year, we strategically repositioned our portfolio to focus capital investment primarilyfarmed-in a significant new opportunity offshore Colombia and progressed various exploration activities in US onshore plays, including the DJ and Delaware Basins and Eagle Ford Shale, and in our international offshore assets in the Eastern Mediterranean and West Africa. The focussupport of our capital programs in these areas is expected to positively impact our future cash flows and margins.
During 2018, we continued to enhance our portfolio, concentrated development capabilities on higher-impact opportunities that can drive substantial long-term value creation, focused on margin improvements and undertook shareholder value initiatives.
We believe implementation of our focused strategy has enhanced our future outlook. During 2018, we accomplished the following:
Portfolio Activities, Including:
sale of a 7.5% working interest in Tamar;
sale of our 50% interest in CONE Gathering LLC and our investment in CNX Midstream Partners common units;
sale of our Gulf of Mexico assets;
expansion of new venture portfoliodrilling efforts in both US onshore and international offshore locations;locations.
executionCompleting Midstream Strategic Review We conducted a strategic review of numerous acreage exchangesour Midstream segment and saleselected to secure more contiguous acreage positions withinretain and increase our ownership in Noble Midstream Partners. We concluded the DJ and Delaware Basins; and
completingreview with the midstream Saddle Butte Acquisition, which expanded utilizationsale of the Advantage Pipeline.
Operational Accomplishments, Including:
progressing Leviathan development to approximately 75% completion andsubstantially all of our remaining on budget and on schedule to flow first gas by the end of 2019;
achieved annual average record gross sales of over 1 Bcf/d in Israel;
advancing natural gas marketing and transportation optionality for the export of Tamar and Leviathan production to Egypt;
progressed the next phase of development offshore West Africa by entering a Heads of Agreement establishing the framework for monetization of natural gas from the Alen field;
increased total US onshore sales volumes by more than 18% from 2017, excluding the impactmidstream interests and assets and our incentive distribution rights to Noble Midstream Partners for total consideration of the Marcellus Shale upstream divestiture,$1.6 billion, including $670 million of cash and continuing shift to an oilier production mix, with approximately 44%38.5 million of our US onshore consolidated sales volumes attributable to crude oil;newly issued Noble Midstream Partners common units.
securing near-term flow assurance and long-term out-of-basin takeaway capacity, including the EPIC firm transport agreement, from the Delaware Basin to the Texas Gulf Coast, with access to export markets;
expanded our midstream footprint capabilities through CGF constructions; and
received approval for the first large-scale CDP which will span our Mustang IDP area.
Financial Initiatives, Including:
Board of Directors authorization to implement a $750 million share repurchase program and subsequent repurchase of 10 million shares of Noble Energy common stock, for $295 million, during the year;
increase in dividends to 11 cents per Noble Energy common share for second, third and fourth quarters and paid dividends of $208 million during 2018;
repayment of $609 million of outstanding debt;
enhancement of financial flexibility via revolving credit facility maturity date extensions, a capacity increase and entry into a new term loan credit facility;
repatriation of $791 million from foreign operations with no US tax impact;
positive mitigation efforts for retained Marcellus Shale firm transportation contracts;
strong liquidity position including cashWe focused on hand and unused borrowing capacity; and
investment grade credit ratings and received improved outlooks from two agencies.
In summary, we believe our current portfolio includes assets which are well-positioned on the industry cost of supply curve, offering growth at financially attractive rates of return. Operationally, we continue to drive efficiencies in our US onshore drilling and completions, while advancing our Eastern Mediterranean and West Africa regional natural gas developments. Financially, we continue to maintainmaintaining our strong balance sheet and robustfinancial liquidity, positionwhich totaled almost $4.5 billion at December 31, 2019. During the year, we early redeemed certain senior notes, extending the average maturity of our total debt portfolio, which is approximately 16 years. We maintained our investment grade rating across all agencies while engagingreturning capital to investors through debt repayments and dividends.
Advancing Environmental, Social and Governance (ESG) InitiativesWe continued our focus on ESG initiatives by identifying opportunities to reduce environmental impact, improve safety, support the communities in shareholder return initiatives.which we operate through social investment, increase transparency, and the diversity of our Board of Directors. We also finished 2019 with a record-low total recordable incident rate in the US onshore.
OPERATING OUTLOOK
Growing Long-Term Value We believe the following guiding principles will contribute to growing long-term value:
Execution of a disciplined capital allocation process by:
| |
| ◦ | designing a flexible investment program aligned with the current commodity price environment; and |
| |
◦ | maintaining a strong balance sheet and liquidity position. |
Enhancing capital efficiencies by:
| |
◦ | utilizing our technical competencies and applying historical learnings from unconventional US shale plays to reduce US onshore finding and development costs.environment. |
Leveraging the benefits of our well-positioned and diversified portfolio, including:
| |
| ◦ | exercising investment optionality and flexibility afforded by our assets, certain of which are held by production; and |
| |
| ◦ | continuing portfolio optimization actions to maximize strategic value. |
Enhancing capital efficiencies by:
| |
| ◦ | utilizing our technical competencies and applying historical learnings from unconventional US shale plays to reduce US onshore exploration and development costs. |
Capitalizing on a currently low-cost offshore environment with execution of high-quality, long-cycle development projects, such as:
| |
| ◦ | progressing Leviathan Phase 1 fieldcontinuing development offshore Israel and monetization ofmonetizing natural gas offshore West Africa. |
Maintaining financial strength through:
| |
| ◦ | focusing operational activities on high-margin, high-return assets; and |
| |
| ◦ | improving overall corporate returns. |
We currently expect that commodity price improvement will be limitedCommitment to people and communities in the first half of 2019 and that this factor, along with the timing of our capital expenditures for US onshore development, Leviathan completion and the Aseng development well, will result in the outspending of our operating cash flows. In the second half of the year, reduced capital spend, plus the positive impact from production growth, will result in improved operating cash flows relative to capital spending.which we operate by:
| |
| ◦ | being a safe and reliable operator; |
| |
| ◦ | complying with applicable air quality rules and environmental regulations; and |
| |
| ◦ | advancing ESG initiatives. |
We believe our approach positions the Company for sustainability, operational efficiency, and long-term success throughout the oil and gas business cycle. Further, we expect our US onshore activity, level, combined with Leviathan Phase 1 natural gas sales expected to commence in late 2019, and our West Africa natural gas monetization strategy, which is expected to result in first gas processing in 2021,efforts towards Alen Gas Monetization, will position us for robustsustainable free cash flow growthgeneration in 2020-2021.
the future. However, if commodity prices are suppressed for an extended period of time, and/or operating cost inflation continues impacting operating margins, we could experience material negative impacts on our revenues, profitability, cash flows, liquidity and proved reserves, and, in response, we may consider reductions in our capital investment program or dividends, asset sales or otherwise.actions to support our financial position. Our production, cash flows, and our stock price could decline as a result of these potential developments. See Item 1A. Risk Factors – The oil and gas industry is cyclical and crudeCrude oil, NGL and natural gas prices are volatile. A reductionprice
volatility, including a substantial or extended decline in the price of these pricescommodities, could have a material adverse effect on our results of operations, ourcash flows, liquidity, and the price of our common stock.
Our 2019 production target is in the range of 345 MBoe/d to 365 MBoe/d.
20192020 Organic Capital Investment Program
Exploration and Production Program Our 20192020 organic capital investment program, which excludes Noble Midstream Partners and acquisition capital, is designed to deliver near and long-term value and is flexible in the current commodity price environment. ExcludingThe 2020 organic capital funded by Noble Midstream Partners and acquisition capital related to the EMG Pipeline, our 2019 organic capitalinvestment program is in the range of $2.4$1.6 to $2.6 billion, with$1.8 billion. The 2020 organic capital investment program is approximately 70% being25% below our 2019 organic capital expenditures, which reflects lower spend on the Leviathan field offshore Israel. Approximately 75% of the 2020 organic capital budget is allocated to US onshore development, and approximately 20% to complete the Leviathan projectprimarily in the Eastern Mediterranean. The remaining portion ofDJ and Delaware Basins, with the organic capital program is designated for Noble retained Midstream activities, drilling of a crude oil development wellremainder allocated to progressing the Alen Gas Monetization in West Africa, expanding gas deliverability in Israel and other exploration and corporate activities.
2019 Budget Principles Our 2019 organic capital program anticipates a lower level of investment directed to our US onshore assets, as compared with 2018. We will continue to advance our US onshore program through investments in liquids-rich and high-return projects, improve execution efficiency, and enhance our midstream business value. In the Eastern Mediterranean, our 2019 organic capital program, excluding acquisition capital related to the EMG Pipeline, includes the investment needed to complete Leviathan Phase 1 development.
We will evaluate the level of capital spending throughout the year based on the following factors, among others, and their effect on project financial returns:
commodity prices, including price realizations on specific crude oil, NGL and natural gas production;
operating and development costs;
production,costs for drilling and delivery commitments, or other contractual obligations;
drilling results;
cash flows from operations and indebtedness levels;
availability of financing or other sources of funding;
impact of new laws and regulations on our business practices, including potential legislative or regulatory changes regarding the use of hydraulic fracturing;
property acquisitions and divestitures;
exploration activity; and
potential changes in the fiscal regimes of the US and other countries in which we operate.an exploratory well offshore Colombia.
Our 2020 production target is in the range of 385 MBoe/d to 405 MBoe/d. In our US onshore business, we expect relatively flat production compared to 2019, with an increase in DJ and Delaware Basin production offset by reductions in the Eagle Ford Shale. We expect to have higher oil volumes in 2020 compared to 2019.
Potential for Future ImpairmentsWe have had in the past, and may incur in the future, impairments of proved and unproved properties. Our impairment assessment as of December 31, 2019 indicated that the carrying amounts of our DJ Basin and Delaware Basin properties were not impaired. However, we believe our Delaware Basin properties, in particular, may be at risk for future impairment. Our Delaware Basin properties have significant book value associated with proved reserves and unproved resources, which were acquired primarily through corporate acquisitions. Through acquisition accounting, acquired asset values are recorded at their estimated fair market values at the time of closing. In 2017, commodity prices, specifically those for domestic NGLs and natural gas, were significantly higher when compared to the current environment.
We believe that it is reasonably likely an impairment could be triggered if there is a decrease in forward commodity price assumptions, a widening of basis differentials, material changes to development plans or an increase in operating or abandonment costs, among other factors. The variable which generates the most significant change in undiscounted future net cash flows is generally the forward commodity price outlook. For purposes of impairment assessment, where contractual pricing is not applicable, our current assumption is based on a five-year strip price for crude oil and natural gas, with prices subsequent to the fifth year held constant. Should our assumptions regarding forward commodity prices decline 5% or more beyond that used as of December 31, 2019, with all other assumptions unchanged, our Delaware Basin properties would be at risk for impairment. As of December 31, 2019, the carrying amount of our Delaware Basin properties was $5.5 billion, of which $3.6 billion was attributable to proved properties, including related Midstream segment assets, with $1.9 billion attributable to unproved properties.
In addition, an extended commodity price downturn could result in the impairment of other proved or unproved properties or long-lived assets, including equity method investments, intangible assets, goodwill and/or right-of-use assets. A future impairment of property or other long-lived asset could have a significant impact on our deferred tax asset and liability balance, and potentially cause us to establish valuation allowances for our deferred tax assets associated with domestic net operating loss carryforwards, which would result in a corresponding increase in income tax expense.
See LiquidityItem 1A. Risk Factors – Crude oil, NGL and Capital Resources – Contractual Obligations.natural gas price volatility, including a substantial or extended decline in the price of these commodities, could have a material adverse effect on our results of operations, cash flows, liquidity, and the price of our common stock. RESULTS OF OPERATIONS – E&P
Highlights for our E&P business were as follows:
20182019 Significant E&P Operating Highlights Included:Highlights:
increased total average consolidated sales volumes of 346by 3% to 355 MBoe/d, net;
increased average daily sales volumes for US onshore crude oil of 109by 10% to 120 MBbl/d, net; and
average daily sales volumesreduced total production expense per BOE by 3% as compared to 2018;
exceeded 2 Tcf, gross, of approximately 1.0 Bcfe/d, gross, offshore Israel, primarilynatural gas produced from the Tamar field.field since commencement of operations;
2018 E&P Financial Results Included:commenced production from the Leviathan field in December 2019;
average realized crude oil price increaseinvested in the EMG Pipeline, through our affiliate, EMED Pipeline B.V., enabling future flow of 25% as compared with 2017;
average realized NGL price increase of 10% as compared with 2017;
average realized natural gas price decrease of 8% as compared with 2017;production from offshore Israel to customers in Egypt;
goodwill impairment charge of $1.3 billion attributable to the Texas reporting unit (associated with the Clayton Williams Energy Acquisition);
pre-tax income of $119reduced capital expenditures, excluding acquisitions, by $571 million as compared with pre-tax loss2018;
drilled the Aseng 6P well, offshore Equatorial Guinea, and commenced production in fourth quarter 2019; and
sanctioned the Alen Gas Monetization project, offshore Equatorial Guinea.
Following is a summarized statement of operations for our E&P business: |
| | | | | | | | | | | |
| | Year Ended December 31, |
| (millions) | 2018 | | 2017 | | 2016 |
Oil, NGL and Gas Sales to Third Parties (1) | $ | 4,461 |
| | $ | 4,060 |
| | $ | 3,389 |
|
| Income from Equity Method Investees | 132 |
| | 120 |
| | 50 |
|
| Total Revenues | 4,613 |
| | 4,180 |
| | 3,439 |
|
Production Expense (1) | 1,358 |
| | 1,270 |
| | 1,200 |
|
| Exploration Expense | 129 |
| | 188 |
| | 925 |
|
| Depreciation, Depletion and Amortization | 1,819 |
| | 1,965 |
| | 2,395 |
|
| Loss on Marcellus Shale Upstream Divestiture and Other | — |
| | 2,286 |
| | — |
|
Gain on Divestitures, Net (2) | (340 | ) | | (326 | ) | | (238 | ) |
Asset Impairments (2) | 169 |
| | 70 |
| | 92 |
|
Goodwill Impairment (3) | 1,281 |
| | — |
| | — |
|
| (Gain) Loss on Commodity Derivative Instruments | (63 | ) | | (63 | ) | | 139 |
|
| Clayton Williams Energy Acquisition Expenses | — |
| | 100 |
| | — |
|
| Income (Loss) Before Income Taxes | 119 |
| | (1,803 | ) | | (1,271 | ) |
|
| | | | | | | |
| | Year Ended December 31, |
| (millions) | 2019 | | 2018 |
| Oil, NGL and Gas Sales to Third Parties | $ | 3,904 |
| | $ | 4,461 |
|
| Sales of Purchased Oil and Gas | 109 |
| | 20 |
|
| Income from Equity Method Investments and Other | 69 |
| | 132 |
|
| Total Revenues | 4,082 |
| | 4,613 |
|
| Production Expense | 1,354 |
| | 1,358 |
|
| Exploration Expense | 202 |
| | 129 |
|
| Depreciation, Depletion and Amortization | 2,058 |
| | 1,819 |
|
Gain on Divestitures, Net (1) | — |
| | (340 | ) |
Asset Impairments (2) | 1,160 |
| | 169 |
|
Goodwill Impairment (2) | — |
| | 1,281 |
|
| Cost of Purchased Oil and Gas | 107 |
| | 20 |
|
| Loss (Gain) on Commodity Derivative Instruments | 143 |
| | (63 | ) |
| (Loss) Income Before Income Taxes | (1,093 | ) | | 119 |
|
Average Oil, NGL and Gas Sales Volumes and Prices Average daily sales volumes from our share of production and average realized sales prices were as follows: | | | | Sales Volumes (1) | | Average Realized Sales Prices (1) | Average Sales Volumes | | Average Realized Sales Prices |
| | Crude Oil & Condensate (MBbl/d) | | NGLs
(MBbl/d) | | Natural Gas (MMcf/d) | | Total (MBoe/d) | | Crude Oil & Condensate (Per Bbl) | | NGLs (Per Bbl) | | Natural
Gas
(Per Mcf) | Crude Oil & Condensate (MBbl/d) | | NGLs
(MBbl/d) | | Natural Gas (MMcf/d) | | Total (MBoe/d) | | Crude Oil & Condensate (Per Bbl) | | NGLs (Per Bbl) | | Natural Gas
(Per Mcf) |
| Year Ended December 31, 2018 | |
| Year Ended December 31, 2019 | | Year Ended December 31, 2019 |
United States (2) | 114 |
| | 62 |
| | 472 |
| | 255 |
| | $ | 61.12 |
| | $ | 25.88 |
| | $ | 2.53 |
| 120 |
| | 68 |
| | 516 |
| | 274 |
| | $ | 55.68 |
| | $ | 14.32 |
| | $ | 1.83 |
|
| Eastern Mediterranean | — |
| | — |
| | 237 |
| | 40 |
| | — |
| | — |
| | 5.47 |
| — |
| | — |
| | 223 |
| | 37 |
| | — |
| | — |
| | 5.55 |
|
West Africa (3) | 16 |
| | — |
| | 213 |
| | 51 |
| | 68.53 |
| | — |
| | 0.27 |
| |
West Africa (1) | | 13 |
| | — |
| | 186 |
| | 44 |
| | 61.03 |
| | — |
| | 0.27 |
|
| Total Consolidated Operations | 130 |
| | 62 |
| | 922 |
| | 346 |
| | 62.01 |
| | 25.88 |
| | 2.76 |
| 133 |
| | 68 |
| | 925 |
| | 355 |
| | 56.21 |
| | 14.32 |
| | 2.41 |
|
Equity Investees (4) | 2 |
| | 5 |
| | — |
| | 7 |
| | 68.99 |
| | 42.14 |
| | — |
| |
Equity Investment (2) | | 2 |
| | 4 |
| | — |
| | 6 |
| | 58.65 |
| | 31.77 |
| | — |
|
| Total | 132 |
| | 67 |
| | 922 |
| | 353 |
| | $ | 62.10 |
| | $ | 27.18 |
| | $ | 2.76 |
| 135 |
| | 72 |
| | 925 |
| | 361 |
| | $ | 56.24 |
| | $ | 15.40 |
| | $ | 2.41 |
|
| Year Ended December 31, 2017 | |
| Year Ended December 31, 2018 | | Year Ended December 31, 2018 |
United States | 111 |
| | 58 |
| | 607 |
| | 270 |
| | $ | 49.11 |
| | $ | 23.40 |
| | $ | 3.02 |
| 114 |
| | 62 |
| | 472 |
| | 255 |
| | $ | 61.12 |
| | $ | 25.88 |
| | $ | 2.53 |
|
| Eastern Mediterranean | — |
| | — |
| | 272 |
| | 46 |
| | — |
| | — |
| | 5.32 |
| — |
| | — |
| | 237 |
| | 40 |
| | — |
| | — |
| | 5.47 |
|
West Africa (3)(1) | 18 |
| | — |
| | 239 |
| | 57 |
| | 53.68 |
| | — |
| | 0.27 |
| 16 |
| | — |
| | 213 |
| | 51 |
| | 68.53 |
| | — |
| | 0.27 |
|
| Total Consolidated Operations | 129 |
| | 58 |
| | 1,118 |
| | 373 |
| | 49.73 |
| | 23.40 |
| | 3.01 |
| 130 |
| | 62 |
| | 922 |
| | 346 |
| | 62.01 |
| | 25.88 |
| | 2.76 |
|
Equity Investees (4) | 2 |
| | 6 |
| | — |
| | 8 |
| | 55.13 |
| | 38.48 |
| | — |
| |
Equity Investment (2) | | 2 |
| | 5 |
| | — |
| | 7 |
| | 68.99 |
| | 42.14 |
| | — |
|
| Total | 131 |
| | 64 |
| | 1,118 |
| | 381 |
| | $ | 49.84 |
| | $ | 24.81 |
| | $ | 3.01 |
| 132 |
| | 67 |
| | 922 |
| | 353 |
| | $ | 62.10 |
| | $ | 27.18 |
| | $ | 2.76 |
|
| Year Ended December 31, 2016 | |
| United States | 99 |
| | 54 |
| | 881 |
| | 301 |
| | $ | 39.59 |
| | $ | 14.92 |
| | $ | 2.11 |
| |
| Eastern Mediterranean | — |
| | — |
| | 281 |
| | 47 |
| | — |
| | — |
| | 5.21 |
| |
West Africa (3) | 26 |
| | — |
| | 235 |
| | 65 |
| | 43.54 |
| | — |
| | 0.27 |
| |
| Total Consolidated Operations | 125 |
| | 54 |
| | 1,397 |
| | 413 |
| | 40.39 |
| | 14.92 |
| | 2.42 |
| |
Equity Investees (4) | 2 |
| | 5 |
| | — |
| | 7 |
| | 45.44 |
| | 26.30 |
| | — |
| |
| Total | 127 |
| | 59 |
| | 1,397 |
| | 420 |
| | $ | 40.46 |
| | $ | 15.96 |
| | $ | 2.42 |
| |
| |
◦ | increases in NGL revenues, and corresponding increase in production expense, of $7 million for 2018; |
| |
◦ | decreases in natural gas revenues, and corresponding decreases in production expense, of $7 million for 2018; |
| |
◦ | increases in NGL and natural gas sales volumes of 5 MBbl/d and 31MMcf/d, respectively, for 2018; and |
| |
◦ | reductions in average realized NGL and natural gas sales prices of $1.76/Bbl and $0.12/Mcf, respectively, for 2018.
|
| |
(4)(2)
| Volumes represent sales of condensate and LPG from the LPG plant in Equatorial Guinea. See Income from Equity Method Investees.Investments and Other. |
An analysis of revenues from sales of crude oil, NGLs and natural gas is as follows: | | | (millions) | | Crude Oil & Condensate | | NGLs | | Natural Gas | | Total | Crude Oil & Condensate | | NGLs | | Natural Gas | | Total |
| Year Ended December 31, 2016 | | $ | 1,854 |
| | $ | 296 |
| | $ | 1,239 |
| | $ | 3,389 |
| |
| Year Ended December 31, 2018 | | $ | 2,945 |
| | $ | 587 |
| | $ | 929 |
| | $ | 4,461 |
|
| Changes due to | | | | | | | | | | | | | | | |
| Increase (Decrease) in Sales Volumes | | 55 |
| | 17 |
| | (182 | ) | | (110 | ) | 68 |
| | 48 |
| | (15 | ) | | 101 |
|
Increase in Sales Prices (1) | | 437 |
| | 180 |
| | 164 |
| | 781 |
| |
| Year Ended December 31, 2017 | | $ | 2,346 |
| | $ | 493 |
| | $ | 1,221 |
| | $ | 4,060 |
| |
| Changes due to | | | | | | | | | |
| Increase (Decrease) in Sales Volumes | | 14 |
| | — |
| | (266 | ) | | (252 | ) | |
Increase (Decrease) in Sales Prices (1) | | 585 |
| | 87 |
| | (19 | ) | | 653 |
| |
| Impact of ASC 606 Adoption | | — |
| | 7 |
| | (7 | ) | | — |
| |
| Year Ended December 31, 2018 | | $ | 2,945 |
| | $ | 587 |
| | $ | 929 |
| | $ | 4,461 |
| |
Decrease in Sales Prices (1) | | (277 | ) | | (281 | ) | | (100 | ) | | (658 | ) |
| Year Ended December 31, 2019 | | $ | 2,736 |
| | $ | 354 |
| | $ | 814 |
| | $ | 3,904 |
|
Crude Oil and Condensate Sales Revenues Revenues from crude oil and condensate sales increaseddecreased in 20182019 as compared with 20172018 due to the following:
higher US onshore sales volumes of 19 MBbl/d primarily driven by an increase in development activity in the Delaware and DJ Basins;
partially offset by:
lower Gulf of Mexico sales volumes of 16 MBbl/d resulting from the sale of the Gulf of Mexico assets in second quarter 2018; and
lower offshore West Africa sales volumes of 2 MBbl/d resulting from natural field decline.
Revenues from crude oil and condensate sales increased in 2017 as compared with 2016 due to the following:
higher US onshorereduction in sales volumes of 16 MBbl/d, including 5 MBbl/d contributed by Clayton Williams Energydue to the sale of our Gulf of Mexico assets primarily attributable to increased development and enhanced well design and completion techniques;in second quarter 2018; and
higherlower offshore West Africa sales volumes of 23 MBbl/d due to full yeartiming of production at Gunflint, a Gulf of Mexico project that started production in July 2016;liftings and natural field decline;
partially offset by:
lower sales volumes of 14 MBbl/d primarily due to natural field decline in the Gulf of Mexico and Equatorial Guinea.
NGL Sales RevenuesRevenues from NGL sales increased in 2018 as compared with 2017 due to the following:
higher US onshore sales volumes of 611 MBbl/d (exclusive of 5 MBbl/d from adoption of ASC 606) primarily attributabledue to an increase in development activitiesactivity in the DJ and Delaware and DJ Basins;Basins.
NGL Sales RevenuesRevenues from NGL sales decreased in 2019 as compared with 2018 due to the following:
$7 million increase associated with the adoptionlower Eagle Ford Shale sales volumes of ASC 606;6 MBbl/d due to reduced activity and natural field decline;
partially offset by:
lowerhigher sales volumes of 512 MBbl/d in the DJ and Delaware Basins due to an increase in development activities.
Natural Gas Sales RevenuesRevenues from natural gas sales decreased in 2019 as compared with 2018 due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017.
Revenues from NGL sales increased in 2017 as compared with 2016 due to the following:
higher US onshorelower Eagle Ford Shale sales volumes of 7 MBbl/41 MMcf/d including 1 MBbl/due to reduced activity and natural field decline;
lower West Africa sales volumes of 28 MMcf/d contributed by Clayton Williams Energy assets,due to natural field decline and planned maintenance at onshore facilities during first quarter 2019, which required shut-in for a portion of the period; and
lower Israel sales volumes of 14 MMcf/d primarily attributabledue to increased development and enhanced well design and completion techniques;the sale of a 7.5% interest in the Tamar field in March 2018;
partially offset by:
lowerhigher sales volumes of 4 MBbl/91 MMcf/d in the DJ and Delaware Basins due to the divestiturean increase in development activity.
Sales and Cost of the Marcellus Shale upstream assets in second quarter 2017.
NaturalPurchased Oil and Gas Sales Revenues Revenues from naturalSales and cost of purchased oil and gas sales decreasedincreased in 20182019 as compared with 2017 due2018 as we engaged in a full year of third-party sales and purchases of crude oil in the DJ Basin in 2019 compared with only fourth quarter sales and purchases in 2018. We enter into these arrangements for flow assurance on pipelines used to the following:deliver our production to market and to cover shortfalls in equity production.
lower sales volumesIncome from Equity Method Investments and OtherOur share of 174 MMcf/d due to the divestitureoperations of the Marcellus Shale upstream assets in second quarter 2017;equity method investments were as follows: |
| | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 |
| Net Income (millions) | | | |
| AMPCO and Affiliates | $ | 23 |
| | $ | 64 |
|
| Alba Plant | 41 |
| | 71 |
|
| Dividends (millions) | | | |
| AMPCO and Affiliates | $ | 9 |
| | $ | 63 |
|
| Alba Plant | 42 |
| | 93 |
|
| Sales Volumes | | | |
| Methanol (Mt/d) | 1,091 |
| | 1,230 |
|
| Condensate (MBbl/d) | 2 |
| | 2 |
|
| LPG (MBbl/d) | 4 |
| | 5 |
|
| Average Realized Prices | | | |
lower Gulf of Mexico sales volumes of 14 MMcf/d resulting |
| | | | | | | |
| Methanol (per Mt) | $ | 269.73 |
| | $ | 379.62 |
|
| Condensate (per Bbl) | 58.65 |
| | 68.99 |
|
| LPG (per Bbl) | 31.77 |
| | 42.14 |
|
Income from the sale of the Gulf of Mexico assets in second quarter 2018;
lower Israel sales volumes of 35 MMcf/d due to the sale of a 7.5% interest in the Tamar field in second quarter 2018;
$7 million decrease associated with the adoption of ASC 606;
lower sales volumes of 26 MMcf/d from the Alba field, offshore Equatorial Guinea, resulting from natural field decline and timing of field maintenance; and
8% decrease in average realized prices primarily due to the impact of increased US onshore supply;
partially offset by:
higher US onshore sales volumes of 30 MMcf/d (exclusive of 31 MMcf/d from adoption of ASC 606) primarily attributable to development activities in the Delaware and DJ Basins; and
higher sales volumes related to our remaining working interest in Israel due to increased demandequity method investments decreased for power as well as conversion of facilities from use of coal to natural gas.
Revenues from natural gas sales decreased slightly in 20172019 as compared with 20162018 due to the following:
lower sales volumes of 312 MMcf/d due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017; and
lower sales volumes of 29 MMcf/d as a result of the sale of a 3.5% working interest in the Tamar field in December 2016, partially offset by higher gross sales volumes from the field;
partially offset by:
higher US onshore sales volumes of 40 MMcf/d, including 6 MMcf/d contributed by Clayton Williams Energy assets.
Income from Equity Method InvesteesOur share of operations of equity method investees were as follows: |
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| Net Income (in millions) | | | | | | |
| AMPCO and Affiliates | | $ | 64 |
| | $ | 58 |
| | $ | 16 |
|
| Alba Plant | | 71 |
| | 65 |
| | 34 |
|
| Dividends (in millions) | | | | | | |
| AMPCO and Affiliates | | $ | 63 |
| | $ | 47 |
| | $ | 16 |
|
| Alba Plant | | 93 |
| | 68 |
| | 40 |
|
| Sales Volumes | | | | | | |
| Methanol (MMgal) | | 149 |
| | 163 |
| | 162 |
|
| Condensate (MBbl/d) | | 2 |
| | 2 |
| | 2 |
|
| LPG (MBbl/d) | | 5 |
| | 6 |
| | 5 |
|
| Average Realized Prices | | | | | | |
| Methanol (per gallon) | | $ | 1.14 |
| | $ | 0.97 |
| | $ | 0.63 |
|
| Condensate (per Bbl) | | 68.99 |
| | 55.13 |
| | 45.44 |
|
| LPG (per Bbl) | | 42.14 |
| | 38.48 |
| | 26.30 |
|
Changes for 2018 as compared with 2017 included the following:
increasedecrease in net income from AMPCO and affiliates primarily due to higherlower realized methanol prices; and
increasedecrease in net income from Alba Plant primarily due to higherlower realized LPG prices.
Changes for 2017 as compared with 2016 included the following:
increase in net income from AMPCO and affiliates primarily due to higher realized methanol prices; and
increase in net income from Alba Plant primarily due to higher LPG sales volumes and realized prices.
Production Expense Components of production expense were as follows: | | | (millions, except unit rate) | Total per BOE (1)(2) | | Total | | United States (2) | | Eastern Mediterranean | | West Africa | Total per BOE (1)(2) | | Total | | United States (2) | | Eastern Mediterranean | | West Africa |
| Year Ended December 31, 2018 | | | | | | | | | | |
Lease Operating Expense (3) | $ | 4.78 |
| | $ | 603 |
| | $ | 480 |
| | $ | 26 |
| | $ | 97 |
| |
| Year Ended December 31, 2019 | | | | | | | | | | |
| Lease Operating Expense | | $ | 4.42 |
| | $ | 573 |
| | $ | 460 |
| | $ | 37 |
| | $ | 76 |
|
| Production and Ad Valorem Taxes | 1.46 |
| | 184 |
| | 184 |
| | — |
| | — |
| 1.30 |
| | 169 |
| | 169 |
| | — |
| | — |
|
Gathering, Transportation and Processing (4) | 4.22 |
| | 533 |
| | 533 |
| | — |
| | — |
| 4.62 |
| | 599 |
| | 598 |
| | 1 |
| | — |
|
| Other Royalty Expense | 0.30 |
| | 38 |
| | 38 |
| | — |
| | — |
| 0.10 |
| | 13 |
| | 13 |
| | — |
| | — |
|
| Total Production Expense | $ | 10.76 |
| | $ | 1,358 |
| | $ | 1,235 |
|
| $ | 26 |
|
| $ | 97 |
| $ | 10.44 |
| | $ | 1,354 |
| | $ | 1,240 |
| | $ | 38 |
| | $ | 76 |
|
| Total Production Expense per BOE | | | $ | 10.76 |
| | $ | 13.28 |
| | $ | 1.79 |
| | $ | 5.20 |
| | | $ | 10.44 |
| | $ | 12.41 |
| | $ | 2.78 |
| | $ | 4.73 |
|
| Year Ended December 31, 2017 | |
| | |
| | |
| | |
| | |
| |
| Year Ended December 31, 2018 | | |
| | |
| | |
| | |
| | |
|
Lease Operating Expense (3) | $ | 4.29 |
| | $ | 585 |
| | $ | 466 |
| | $ | 29 |
| | $ | 90 |
| $ | 4.78 |
| | $ | 603 |
| | $ | 480 |
| | $ | 26 |
| | $ | 97 |
|
| Production and Ad Valorem Taxes | 0.84 |
| | 115 |
| | 115 |
| | — |
| | — |
| 1.46 |
| | 184 |
| | 184 |
| | — |
| | — |
|
| Gathering, Transportation and Processing | 4.04 |
| | 550 |
| | 550 |
| | — |
| | — |
| 4.22 |
| | 533 |
| | 533 |
| | — |
| | — |
|
| Other Royalty Expense | 0.15 |
| | 20 |
| | 20 |
| | — |
| | — |
| 0.30 |
| | 38 |
| | 38 |
| | — |
| | — |
|
| Total Production Expense | $ | 9.32 |
| | $ | 1,270 |
| | $ | 1,151 |
| | $ | 29 |
| | $ | 90 |
| $ | 10.76 |
| | $ | 1,358 |
| | $ | 1,235 |
| | $ | 26 |
| | $ | 97 |
|
| Total Production Expense per BOE | | | $ | 9.32 |
| | $ | 11.68 |
| | $ | 1.74 |
| | $ | 4.28 |
| | | $ | 10.76 |
| | $ | 13.28 |
| | $ | 1.79 |
| | $ | 5.20 |
|
| Year Ended December 31, 2016 | | | | | | | | | | |
Lease Operating Expense (3) | $ | 3.72 |
| | $ | 560 |
| | $ | 418 |
| | $ | 37 |
| | $ | 105 |
| |
| Production and Ad Valorem Taxes | 0.36 |
| | 55 |
| | 55 |
| | — |
| | — |
| |
| Gathering, Transportation and Processing | 3.73 |
| | 564 |
| | 564 |
| | — |
| | — |
| |
| Other Royalty Expense | 0.14 |
| | 21 |
| | 21 |
| | — |
| | — |
| |
| Total Production Expense | $ | 7.95 |
| | $ | 1,200 |
| | $ | 1,058 |
| | $ | 37 |
| | $ | 105 |
| |
| Total Production Expense per BOE | | | $ | 7.95 |
| | $ | 9.63 |
| | $ | 2.14 |
| | $ | 4.42 |
| |
| |
(1) | Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.investments. |
| |
(3)
| Lease operating expense includes oil and gas operating costs (labor, fuel, repairs, replacements, saltwater disposal and other related lifting costs) and workover expense. |
Lease Operating Expense Lease operating
Production expense increaseddecreased in 20182019 as compared with 2017 primarily due to the following:
increase of $93 million primarily due to increased development activities resulting in added production in the DJ and Delaware Basins; and
increase in costs in the Delaware Basin due to higher activity and demand for supplies and services, particularly water disposal;
partially offset by:
decrease of $84 million due to lower production in the Gulf of Mexico resulting from natural field decline and the subsequent sale of the assets in second quarter 2018; and
decrease of $13 million related to the divestiture of the Marcellus Shale upstream assets in second quarter 2017.
Lease operating expense increased in 2017 as compared with 20162018 primarily due to the following:
increase of $82 milliondecrease in US lease operating expense primarily due to the sale of our Gulf of Mexico assets and cost reduction efforts, notably workover reductions and compression optimization, in the US onshore basins; and
decrease in other royalty expense due to lower commodity prices;
decrease in West Africa lease operating expense due to cost reduction efforts across all assets; and
decrease in production and ad valorem taxes due to production tax refunds;
partially offset by:
increase in US gathering, transportation and processing (GTP) expense primarily due to increased development activity in the DJ Basin and higher-cost Delaware BasinBasin; and Eagle Ford Shale
increase in Eastern Mediterranean lease operating expense due to increased activity;planned maintenance activities.
The decrease in the unit rate per BOE for 2019 compared to 2018 is primarily due to cost reduction efforts in US onshore basins and West Africa, partially offset by:
decrease of $19 million resultingby an increase in GTP expense and an increase in volumes from natural field decline in the Gulf of Mexico;
decrease of $17 million related to the divestiture of the Marcellus Shale upstream assets in second quarter 2017;
decrease of $15 million due to various cost reduction initiatives offshore West Africa; and
decrease of $11 million due to a 3.5% lower working interest in the Tamar field following the partial divestiture in December 2016.higher-cost areas within US onshore.
Production and Ad Valorem TaxExploration Expense ProductionThe increase in exploration expense for 2019 is primarily due to the write-off of $100 million of Leviathan Deep exploratory well costs. This increase was partially offset by reductions in lease rentals and ad valorem taxes increased in 2018staff expense as compared with 2017, primarily due to higher commodity prices.2018. See Item 8. Financial Statements and Supplementary Data – Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
ProductionDepreciation, Depletion and ad valorem taxes increased in 2017 as compared with 2016, primarily due to higher commodity prices and a $28 million US onshore severance tax refund recorded in first quarter 2016 versus a $7 million US onshore severance tax charge recorded in first quarter 2017.
Gathering, Transportation and Processing Expense Gathering, transportation and processing expense decreased in 2018 as compared with 2017 primarily due to:
decrease of $17 million in the Gulf of Mexico due to lower production resulting from natural field decline and the subsequent sale of the assets in second quarter 2018; and
decrease of $88 million related to the divestiture of the Marcellus Shale upstream assets in second quarter 2017;
partially offset by:
increase of $63 million related to increased activity in Delaware and DJ Basins.
Gathering, transportation and processing expense remained relatively flat in 2017 as compared with 2016 primarily due to:
decrease of $120 million related to the divestiture of the Marcellus Shale upstream assets in second quarter 2017;
partially offset by:
increase of $57 million in the DJ Basin due to the shifting of crude oil volumes onto a new export pipeline and contractual increases of pipeline fees; and
increase of $47 million related to higher production in the Delaware Basin and Eagle Ford Shale.
Other RoyaltyAmortization (DD&A) Expense Other royaltyDD&A expense increased in 2018 as compared with 2017, primarily due to higher commodity prices. Other royalty expense remained relatively flat in 2017 as compared with 2016.
Unit Rate Per BOEProduction expense on a per BOE basis increased in 2018 as compared with 2017, primarily due to the decrease in total sales volumes driven by divestitures of the Marcellus Shale upstream assets in second quarter 2017 and Gulf of Mexico assets in second quarter 2018, which lowered our average production expense per BOE. These impacts were offset by an increase in volumes from the higher cost Delaware Basin.
Production expense on a per BOE basis increased in 2017 as compared with 2016, primarily due to the increases in certain production expenses noted above. In addition, the Marcellus Shale upstream divestiture resulted in the removal of lower-cost, natural gas-focused sales volumes from our portfolio, while an increase in Delaware Basin and Eagle Ford Shale volumes contributed higher-cost, crude oil-focused sales volumes, thereby increasing our average production expense per BOE. Also, higher commodity prices led to higher production and ad valorem taxes per BOE.
Exploration ExpenseComponents of exploration expense werewas as follows: |
| | | | | | | | | | | | | | | | | | | |
| (millions) | Total | | United States | | Eastern Mediter-ranean | | West Africa | | Other Int'l |
| Year Ended December 31, 2018 | | | |
| | |
| | |
| | |
|
| Leasehold Impairment and Amortization | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
|
Dry Hole Cost (1) | 1 |
| | 1 |
| | — |
| | — |
| | — |
|
| Seismic, Geological and Geophysical | 22 |
| | 8 |
| | 3 |
| | — |
| | 11 |
|
| Staff Expense | 54 |
| | 41 |
| | 2 |
| | 5 |
| | 6 |
|
Other (2) | 51 |
| | (3 | ) | | 2 |
| | 1 |
| | 51 |
|
| Total Exploration Expense | $ | 129 |
| | $ | 48 |
| | $ | 7 |
| | $ | 6 |
| | $ | 68 |
|
| Year Ended December 31, 2017 | | | | | | | | | |
| Leasehold Impairment and Amortization | $ | 62 |
| | $ | 60 |
| | $ | — |
| | $ | — |
| | $ | 2 |
|
Dry Hole Cost (1) | 9 |
| | — |
| | — |
| | — |
| | 9 |
|
| Seismic, Geological and Geophysical | 27 |
| | 8 |
| | — |
| | — |
| | 19 |
|
| Staff Expense | 55 |
| | 1 |
| | 2 |
| | 4 |
| | 48 |
|
Other (2) | 35 |
| | 33 |
| | — |
| | 1 |
| | 1 |
|
| Total Exploration Expense | $ | 188 |
| | $ | 102 |
| | $ | 2 |
| | $ | 5 |
| | $ | 79 |
|
| Year Ended December 31, 2016 | | | |
| | |
| | |
| | |
|
| Leasehold Impairment and Amortization | $ | 148 |
| | $ | 123 |
| | $ | — |
| | $ | — |
| | $ | 25 |
|
Dry Hole Cost (1) | 579 |
| | 85 |
| | 26 |
| | 468 |
| | — |
|
| Seismic, Geological and Geophysical | 76 |
| | — |
| | — |
| | 10 |
| | 66 |
|
| Staff Expense | 77 |
| | 3 |
| | 1 |
| | 5 |
| | 68 |
|
Other (2) | 45 |
| | 34 |
| | 7 |
| | — |
| | 4 |
|
| Total Exploration Expense | $ | 925 |
| | $ | 245 |
| | $ | 34 |
| | $ | 483 |
| | $ | 163 |
|
|
| | | | | | | | | | | | | | | | | | | |
| (millions, except unit rate) | Total | | United States | | Eastern Mediterranean | | West Africa | | Other Int'l |
| Year Ended December 31, 2019 | | | | | | | | | |
DD&A Expense (1) | $ | 2,058 |
| | $ | 1,907 |
| | $ | 67 |
| | $ | 83 |
| | $ | 1 |
|
Unit Rate per BOE (2) | $ | 15.88 |
| | $ | 19.09 |
| | $ | 4.91 |
| | $ | 5.16 |
| | $ | — |
|
| Year Ended December 31, 2018 | | | | | | | | | |
DD&A Expense (1) | $ | 1,819 |
| | $ | 1,642 |
| | $ | 60 |
| | $ | 115 |
| | $ | 2 |
|
Unit Rate per BOE (2) | $ | 14.42 |
| | $ | 17.66 |
| | $ | 4.13 |
| | $ | 6.17 |
| | $ | — |
|
| |
(2) | Includes lease rentalConsolidated rates exclude sales volumes and other exploration expense.expenses attributable to equity method investments. |
Exploration expense for 2018 included:
staff expense incurred across our US onshore assets.
Exploration expense for 2017 included:
leasehold impairment expense related primarily to Gulf of Mexico unproved properties; and
dry hole cost of $7 million for the Araku-1 exploration well, offshore Suriname.
Exploration expense for 2016 included:
leasehold impairment expense, including the write-off of leases and licenses, of $58 million for the Gulf of Mexico, $25 million for other international locations, and $10 million for other US onshore; and
dry hole cost including costs related to the Silvergate exploratory well, Gulf of Mexico, the Dolphin 1 natural gas discovery, offshore Israel, and certain discoveries offshore West Africa.
Depreciation, Depletion and Amortization ExpenseDepreciation, Depletion and Amortization (DD&A) expense was as follows: |
| | | | | | | | | | | | | | | | | | | |
| (millions, except unit rate) | Total | | United
States | | Eastern
Mediter- ranean | | West
Africa | | Other Int'l |
| Year Ended December 31, 2018 | | | | | | | | | |
| DD&A Expense | $ | 1,819 |
| | $ | 1,642 |
| | $ | 60 |
| | $ | 115 |
| | $ | 2 |
|
Unit Rate per BOE (1) | $ | 14.42 |
| | $ | 17.66 |
| | $ | 4.13 |
| | $ | 6.17 |
| | $ | — |
|
| Year Ended December 31, 2017 | | | | | | | | | |
| DD&A Expense | $ | 1,965 |
| | $ | 1,739 |
| | $ | 76 |
| | $ | 146 |
| | $ | 4 |
|
Unit Rate per BOE (1) | $ | 14.42 |
| | $ | 17.65 |
| | $ | 4.56 |
| | $ | 6.95 |
| | $ | — |
|
| Year Ended December 31, 2016 | | | | | | | | | |
| DD&A Expense | $ | 2,395 |
| | $ | 2,103 |
| | $ | 81 |
| | $ | 205 |
| | $ | 6 |
|
Unit Rate per BOE (1) | $ | 15.87 |
| | $ | 19.14 |
| | $ | 4.69 |
| | $ | 8.63 |
| | $ | — |
|
(1) DD&A expense includes accretion of discount on AROs of $33 million in 2018, $47 million in 2017, and $48 million in 2016.
Total DD&A expense decreasedincreased in 20182019 as compared with 20172018 primarily due to the following:
decrease of $223 million due to both lower sales volumescapital investment and development activities in the Gulf of Mexico resulting from natural field declineDJ and classification of the assets as held for sale in first quarter 2018,Delaware Basins resulting in the cessation of DD&A expense;
decrease of $15 million due to reclassification of a 7.5% working interest in the Tamar field as assets held for sale at December 31, 2017, resulting in cessation of DD&A expense;higher sales volumes; and
decrease of $90 millionincrease in Eastern Mediterranean primarily due to the Marcellus Shale upstream divestitureretirement of certain capital assets resulting in second quarter 2017;accelerated depreciation;
partially offset by:
higherdecrease resulting from the sale of our Gulf of Mexico assets in second quarter 2018; and
reduced sales volumes in the Delaware Basin, which almost doubled, due to increased development activities subsequent to the Clayton Williams Energy Acquisition in second quarter 2017.West Africa, as noted above, from natural field decline.
The unit rate per BOE for 2018 was flat2019 increased as compared with 2017, primarily2018 due to the increased development activity in the higher cost oil-rich Delaware Basin resulting in higher depletable basis and the sales2018 sale of lower-cost production from our 7.5% interestTamar reserves, which increased the overall unit rate per BOE. The increase in the Tamar field in first quarter 2018 and the Marcellus Shale upstream assets in second quarter 2017,unit rate is partially offset by a decrease in total DD&A expense combined with the sale of higher-cost production from the Gulf of Mexico assets in second quarter 2018.
Total DD&A expense decreased in 2017Loss (Gain) on Commodity Derivative InstrumentsCommodity derivative activity was as compared with 2016 primarilyfollows:
For 2019, the loss on commodity derivative instruments was due to the following:
year-end reserve additions, primarily in US onshore due to enhanced well designnet cash receipt of $32 million; and completion techniques in our horizontal drilling program and globally due to positive price revisions;
lower sales volumesnet non-cash decrease of $175 million in the DJ Basin and the impactfair value of certain property divestitures since the second quarter 2016;
decrease of $291 million due to the Marcellus Shale upstream divestiture in second quarter 2017;
decrease of $7 million due to the sale of a 3.5% working interest in the Tamar field in December 2016;
decrease of $37 million due to a reduction in depletable costs of $153 million due to the reallocation of common asset costs from the Alen field, offshore Equatorial Guinea, to the West Africa natural gas monetization development project in second quarter 2017; and
lower sales volumes in the Gulf of Mexico resulting from natural field decline and reduction in the depletable costs due to downward revisions in estimates of ARO costs;
partially offset by:
higher US onshore sales volumes of 29 MBoe/d, including 7 MBoe/d contributed by Clayton Williams Energy assets;
increase in sales volumes from the Gunflint development, Gulf of Mexico, which commenced production in July 2016; and
higher gross sales volumes from the Tamar field due to higher domestic demand.
The unit rate per BOE for 2017 decreased as compared with 2016, primarily due to year-end reserve additions in US onshore, a reduction in the Alen fieldour net book value in second quarter 2017, and certain DJ Basin property divestitures. These decreases were offset by the commencement of sales volumes from new crude oil-focused wells in US onshore, as well as the divestiture of natural gas-focused sales volumes from Marcellus Shale upstream assets.
(Gain) Loss on Commodity Derivative Instruments (Gain) loss on commodity derivative instruments includes (i) cash settlements paid/received relating to our crude oil and natural gas commodity derivative contracts; and (ii) non-cash decreases/liability, primarily driven by increases in the fair values of ourforward commodity price curve for crude oil and natural gas commodity derivative contracts.oil.
For 2018, gain on commodity derivative instruments included:
net cash settlement payment of $161 million; and
net non-cash increase of $224 million in the fair value of our net commodity derivative asset, primarily driven by decreases in the forward commodity price curve for crude oil.
For 2017, gain on commodity derivative instruments included:
net cash settlement receipt of $13 million; and
net non-cash increase of $50 million in the fair value of our net commodity derivative liability, primarily driven by changes in the forward commodity price curves for both crude oil and natural gas.
For 2016, loss on commodity derivative instruments included:
net cash settlement receipt of $569 million; and
net non-cash decrease of $708 million in the fair value of our net commodity derivative liability, primarily driven by changes in the forward commodity price curves for both crude oil and natural gas.
RESULTS OF OPERATIONS – MIDSTREAM
The Midstream segment develops, owns, operates and acquires domestic midstream infrastructure assets, or invests in other midstream entities, with current focus areas being the DJ and Delaware Basins.
Results of Operations
Highlights for the Midstream segment were as follows:
20182019 Significant Midstream Operating Highlights Included:Highlights:
completed the Saddle Butte Acquisition;sold substantially all of our US onshore midstream interests and assets and our incentive distribution rights to Noble Midstream Partners for total consideration of $1.6 billion;
completed construction of the Coronado, Collier and Billy Miner Train II CGFs in the Delaware Basin;
completed construction of freshwater delivery infrastructure and commenced gathering services in the DJ Basin;
signed a non-binding letter of intent with Salt Creek for construction of a crude oil pipeline systemexpanded our long-haul business by developing strategic relationships in the Delaware Basin, for which definitive agreementsexercising investment options in EPIC Y-Grade and EPIC Crude Holdings, and forming the Delaware Crossing crude oil pipeline joint venture, with Salt Creek were executed in February 2019;total equity contributions of approximately $590 million; and
commenced natural gas compressionsecured long-term takeaway at a lower cost in the Delaware Basin; andDJ Basin through a strategic relationship with Saddlehorn.
in first quarter 2019, exercised options to acquire equity interests in
Following is a summarized statement of operations for the EPIC Y-Grade Pipeline and the EPIC Crude Oil Pipeline.Midstream segment: 2018 Midstream Financial Results Included:
pre-tax income of $726 million, as compared with pre-tax income of $233 million for 2017;
net proceeds of approximately $696 million received, and gain of $503 million recognized, on the sale of our interest in CONE Gathering and sale of our investment in CNX Midstream Partners common units; and
capital expenditures, excluding acquisitions, of $521 million, as compared with $399 million for 2017. |
| | | | | | | |
| | Year Ended December 31, |
| (millions) | 2019 | | 2018 |
| Midstream Services Revenues - Third Party | $ | 94 |
| | $ | 78 |
|
| Sales of Purchased Oil and Gas | 190 |
| | 142 |
|
| (Loss) Income from Equity Method Investments | (18 | ) | | 40 |
|
| Intersegment Revenues | 427 |
| | 351 |
|
| Total Revenues | 693 |
| | 611 |
|
Following is a summarized statement of operations for the Midstream segment: |
| | | | | | | | | | | |
| | Year Ended December 31, |
| (millions) | 2018 | | 2017 | | 2016 |
| Midstream Services Revenues – Third Party | $ | 78 |
| | $ | 19 |
| | $ | — |
|
| Sales of Purchased Oil | 142 |
| | — |
| | — |
|
| Income from Equity Method Investees | 40 |
| | 57 |
| | 52 |
|
| Intersegment Revenues | 351 |
| | 277 |
| | 200 |
|
| Total Revenues | 611 |
| | 353 |
| | 252 |
|
| Operating Costs and Expenses | 128 |
| | 90 |
| | 57 |
|
| Depreciation, Depletion and Amortization | 87 |
| | 30 |
| | 19 |
|
| Gain on Divestiture, Net | (503 | ) | | — |
| | — |
|
| Asset Impairments | 37 |
| | — |
| | — |
|
| Cost of Purchased Oil | 136 |
| | — |
| | — |
|
| Total (Income) Expense | (115 | ) | | 120 |
| | 76 |
|
| Income Before Income Taxes | 726 |
| | 233 |
| | 176 |
|
|
| | | | | | | |
| Operating Costs and Expenses | 150 |
| | 128 |
|
| Depreciation, Depletion and Amortization | 104 |
| | 87 |
|
| Gain on Divestiture, Net | — |
| | (503 | ) |
| Asset Impairments | — |
| | 37 |
|
| Cost of Purchased Oil and Gas | 181 |
| | 136 |
|
| Total Expense (Income) | 435 |
| | (115 | ) |
| Income Before Income Taxes | $ | 258 |
| | $ | 726 |
|
Midstream Services Revenues - Third Party The amount of revenue generated by the Midstream segment depends primarily on the volumes of crude oil, natural gas and water for which services are provided to dedicated acreage for our E&P business and to third-party customers. These volumes are affected by the level of drilling and completion activity in our areas of upstream operations and by changes in the supply of, and demand for, crude oil, NGLs and natural gas in the markets served directly or indirectly by our midstream assets.
TotalMidstream segment services revenues for 2019 increased $16 million as compared with 2018 primarily due to increases in crude oil, natural gas and produced water gathering services and fresh water delivery. The increases were due primarily to higher Delaware Basin throughput volumes, a full year of services in the Mustang IDP and a full year of services related to the Black Diamond System, which was acquired in first quarter 2018.
Sales and Cost of Purchased Oil and GasSales and cost of purchased oil and gas for 2019 increased from 2017 primarily$48 million as compared with 2018 due to an increase in crude oil, produced water and natural gas gathering services and fresh water delivery revenues due to the commencement of services in the Greeley Crescent IDP area of the DJ Basin and the Delaware Basin. In addition, in first quarter 2018, Noble Midstream Partners acquired an interest in Black Diamond which completed the Saddle Butte Acquisition of a large-scale integrated gathering system and associated third-party contracts which include transactions for the purchase and sale of crude oil with varying counterparties. The purchases and sales of crude oil are at the prevailing market prices.
Total revenues for 2017 increased from 2016 primarily due to increases of $60 million and $17 millionthroughput volumes driven by our drilling and completion activities in the DJ and Delaware Basins, respectively, and an increase of $19 million primarily due to commencement of services in the DJ Basin to an unaffiliated third-party.additional well connections.
(Loss) Income from Equity Method InvesteesInvestments Midstream's share of operations ofThe 2019 amount decreased as compared to 2018 due to operating costs incurred by Noble Midstream Partners' equity method investees wasinvestments prior to commencement of full service operations, as well as a decrease in income of $24 million due to the sale of our investments in CONE Gathering LLC and CNX Midstream Partners LP (NYSE: CNXM) in 2018.
Operating Costs and Expenses Total expense for 2019 increased by $22 million as compared with 2018 due to an increase in gathering systems operating expense associated with the Delaware Basin CGFs that were completed in 2018, additional expenses associated with the Black Diamond System and expenses associated with the commencement of gathering services in the Mustang IDP in 2018.
DD&A ExpenseDD&A expense for 2019 increased by $17 million as compared with 2018 primarily due to certain assets being placed in service throughout 2018, including the Mustang IDP gathering system, the Delaware Basin CGFs, and additional Black Diamond assets. In addition, DD&A expense includes a full year of amortization related to intangible assets acquired in the Saddle Butte acquisition.
RESULTS OF OPERATIONS – CORPORATE
Interest expenses and other debt-related costs, headquarters depreciation, corporate G&A expenses, exit costs and certain other costs associated with mitigating the effects of our retained Marcellus Shale transportation agreements are recorded at the Corporate level.
Transportation Exit CostRevenues and expenses associated with retained Marcellus Shale firm transportation contracts were as follows: |
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| (millions) | | 2018 | | 2017 | | 2016 |
| Net Income | | | | | | |
CONE Gathering and CONE Midstream (1) | | $ | 24 |
| | $ | 51 |
| | $ | 48 |
|
| Advantage Pipeline | | 12 |
| | 2 |
| | — |
|
| Other | | 4 |
| | 4 |
| | 5 |
|
| Dividends | | | | | | |
CONE Gathering and CONE Midstream (1) | | 19 |
| | 25 |
| | 27 |
|
| Advantage Pipeline | | 9 |
| | — |
| | — |
|
|
| | | | | | | |
| | Year Ended December 31, |
| (millions) | 2019 | | 2018 |
Sales of Purchased Gas (1) | $ | 90 |
| | $ | 113 |
|
Cost of Purchased Gas (1) | 143 |
| | 140 |
|
Firm Transportation Exit Cost (2) | 88 |
| | — |
|
| |
(1) | Relates to third-party mitigation activities we engage in to utilize a portion of our Marcellus Shale transportation commitments. Cost of purchased gas includes utilized and unutilized transportation expense. |
| |
| Includes exit costs related to future commitments to a third-party resulting from a permanent capacity assignment. |
Total expense for 2018 increased by $38 million as compared with 2017 due to the following:
increase of $21 million due to the addition of expenses associated with the Black Diamond gathering system acquired in the Saddle Butte Acquisition in first quarter 2018;
increase of $12 million in gathering, transportation and processing expense associated with the new CGFs in the Delaware Basin and commencement of gathering services in the Mustang IDP area of the DJ Basin.
Total expense for 2017 increased by $33 million as compared with 2016 due to the following:
increase of $20 million in water services expense due to increased services provided by third parties as well as higher throughput volumes associated with fresh water services;
increase of $6 million in gathering and facilities operating expense due to higher gathered volumes, as well as due to new systems placed in service and expansion of the gathering infrastructure in 2017; andSupplementary Data – Note 11. Exit Cost – Transportation Commitments.
increase of $7 million in general and administrative and other expenses, primarily related to increased third-party legal and advisory fees resulting from transactions.
DD&A Expense DD&A expense for 2018 increased by $57 million as compared with 2017 primarily due to tangible assets acquired in the Saddle Butte Acquisition, assets placed in service in 2018, specifically the CGFs in the Delaware Basin and gathering system in the DJ Basin, and an increase of $30 million related to amortization of customer-related intangible assets acquired in the Saddle Butte Acquisition.
DD&A expense for 2017 increased by $11 million as compared with 2016 primarily due to the assets placed in service in 2017, specifically assets associated with the construction of the Greeley Crescent facilities and the Delaware Basin gathering systems, including completion of two CGFs, and expansion of gathering and fresh water systems in the Wells Ranch, East Pony and Mustang IDP areas.
Salt Creek Joint Venture In October 2018, Noble Midstream Partners entered into a non-binding letter of intent with Salt Creek to form a 50/50 joint venture to construct a 160 MBbl/d day crude oil pipeline system in the Delaware Basin. On February 7, 2019, Noble Midstream Partners executed definitive agreements and completed the formation of Delaware Crossing.
The 95-mile 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. The project is underpinned by approximately 192,000 dedicated gross acres and nearly 100 miles of gathering pipeline in Pecos, Reeves, Ward and Winkler Counties, Texas. The pipeline is expected to be operational in second quarter 2019.
RESULTS OF OPERATIONS – CORPORATE
Our Corporate costs include exit and certain costs associated with mitigating the effects of our retained Marcellus Shale firm transportation agreements and expenses related to debt, headquarters depreciation, and corporate general and administrative expenses.
Marcellus Shale Firm Transportation Contracts Revenues and expenses associated with retained Marcellus Shale firm transportation contracts were as follows:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| (millions) | 2018 | | 2017 | | 2016 |
| Sales of Purchased Gas | $ | 113 |
| | $ | — |
| | $ | — |
|
Loss on Marcellus Shale Upstream Divestiture and Other (1) | — |
| | (93 | ) | | — |
|
| Cost of Purchased Gas | (140 | ) | | — |
| | — |
|
| |
(1)
| Represents accrued non-cash exit costs related to certain retained Marcellus Shale firm transportation contracts. |
General and Administrative ExpenseGeneral and administrative (G&A)G&A expense was as follows: | | | | Year Ended December 31, | Year Ended December 31, |
| (millions, except unit rate) | 2018 | | 2017 | | 2016 | 2019 | | 2018 |
| G&A Expense | $ | 385 |
| | $ | 415 |
| | $ | 399 |
| $ | 416 |
| | $ | 385 |
|
Unit Rate per BOE (1) | $ | 3.05 |
| | $ | 3.05 |
| | $ | 2.64 |
| $ | 3.21 |
| | $ | 3.05 |
|
| |
(1) | Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.investments. |
On a gross basis,The 2019 increase to G&A expense for 2018 increased as compared with 2017is primarily due to increased employee overhead related costsincentive compensation awards, which reflected strong operating performance and campaign and government relations costs related to Colorado Proposition #112. On a net basis, G&A expense for 2018 decreased as compared with 2017 due to enhanced recovery of overhead costs. The unit rate per BOE was flat as compared with 2017.
G&A expense for 2017 increased slightly as compared with 2016 primarily due to increased employee costs driven by acquisition activities.major project execution. The increase in the unit rate per BOE for 20172019 as compared with 20162018 was due primarily to the decreaseincrease in G&A expense, partially offset by the increase in total sales volumes driven by the divestiture of the Marcellus Shale upstream assets.volumes.
G&A expense is impacted by the number of stock-based awards, the market price of our common stock and price volatility which may result in a higher or lower fair value of stock-based awards as calculated using various valuation models. G&A expense included stock-based compensation expense of $59 million in 2019 and $54 million in 2018, $56 million in 2017 and $62 million in 2016.2018. See Item 8. Financial Statements and Supplementary Data – Note 17.16. Stock-Based and Other Compensation Plans. Interest Expense and Capitalized Interest Interest expense and capitalized interest were as follows: | | | | Year Ended December 31, | Year Ended December 31, |
| (millions, except unit rate) | 2018 | | 2017 | | 2016 | 2019 | | 2018 |
| Interest Expense | $ | 355 |
| | $ | 403 |
| | $ | 412 |
| $ | 362 |
| | $ | 355 |
|
| Capitalized Interest | (73 | ) | | (49 | ) | | (84 | ) | (102 | ) | | (73 | ) |
| Interest Expense, Net | $ | 282 |
| | $ | 354 |
| | $ | 328 |
| $ | 260 |
| | $ | 282 |
|
Unit Rate per BOE (1) | $ | 2.23 |
| | $ | 2.60 |
| | $ | 2.17 |
| $ | 2.01 |
| | $ | 2.23 |
|
| |
(1) | Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.investments. |
Interest expense for 2018 decreased2019 increased slightly as compared with 2017 primarily due to a decrease in the overall debt balance. In fourth quarter 2017, we repaid our former $550 million Term Loan Facility due January 6, 2019. In 2018, we repaid $379 million of Senior Notes due May 1, 2021 and $230 million, net, on our Revolving Credit Facility. In addition, in third quarter 2017, we conducted a tender offer and refinanced our 8.25% Senior Notes, resulting in a lower interest rate and lower interest expense, gross, for 2018 as compared with 2017. These financing activities were partially offset by an increase in Noble Midstream Partners debt of $475 million, which was primarily used to fund the first quarter 2018 Saddle Butte Acquisition.
Capitalized interest for 2018 increased as compared with 2017 primarily due to higher work in progress amounts related to Leviathan development.
Interest expense for 2017 decreased as compared with 2016 primarily due to the third quarter 2017 refinancing of our 8.25% senior notes and fourth quarter 2017 repayment of our Term Loan Facility due January 6, 2019.
Capitalized interest for 2017 decreased as compared with 2016 primarily due to the write off of discoveries offshore Equatorial Guinea, lower work in progress amounts related to major long-term projects, including Gunflint, Gulf of Mexico, and the Alba B3 compression project, offshore Equatorial Guinea, partially offset by a higher work in progress amount related to the Leviathan development project.
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 offshore West Africa and offshore Eastern Mediterranean.2018. See Item 8. Financial Statements and Supplementary Data – Note 7.8. Long-Term Debt. Capitalized Exploratory Well Costsinterest for 2019 increased as compared with 2018 primarily due to higher work in progress amounts related to Leviathan development and Undeveloped Leasehold Costsadditions to our Midstream segment equity method investments engaged in construction activities..The unit rate per BOE for 2019 decreased as compared with 2018, primarily due to the reduction in net interest expense and the increase in total sales volumes.
LIQUIDITY AND CAPITAL RESOURCES
Capital Structure/Financing Strategy
In seeking to effectively fund development and monetize our discovered hydrocarbons, we employ a capital structure and financing strategy designed to provide sufficient liquidity throughout commodity price cycles, including a sustained period of low prices. Specifically, weWe strive to retain the ability to fund long cycle, multi-year, capital intensive development projects throughout a range of scenarios, while also funding a continuing exploration program and maintaining capacity to capitalize on financially attractive merger and acquisition opportunities. We endeavor to maintain a strong balance sheet and an investment grade debt rating in service of these objectives.
We strive to maintain a minimum liquidity level to address volatility and risk. TraditionalOur sources of liquidity are primarily cash flows from operations, cash on hand, proceeds from divestitures of properties and other investments, commercial paper borrowings and available borrowing capacity under our $4.0 billion unsecured Revolving Credit Facility.Facilities (defined below). We occasionally access the capital markets to ensure adequate liquidity exists in the form of unutilized capacity under our Revolving Credit FacilityFacilities or to refinance scheduled debt maturities.
maturities. In 2019, we put in place a $4.0 billion commercial paper program to provide for short-term funding needs. We also evaluate potential strategic farm-out arrangements of our working interests for reimbursement of our capital spending. We periodically consider repatriations of foreign cash to increase our financial flexibility and fund our capital investment program. We alsoAdditionally, we enter into crude oil and natural gascommodity price hedging arrangements in an effort to mitigate the effects of commodity price volatility and enhance the predictability of cash flows relating to the marketing of a portion of our crude oil and natural gas production.
Our portfolio transformation strategy, primarily executed during 2017, continued into 2018, with the sales
In 2018,2019, we funded our capital investment program through organicwith cash flows from operations, cash on hand, commercial paper borrowings, proceeds from divestituresdivestments of non-strategic assets, proceeds from the Midstream segment asset divestiture to Noble Midstream Partners, and when needed, borrowings under our Revolving Credit Facility.other sources of funding. During the year, we borrowed and repaid amountsdid not repurchase any shares of Noble Energy common stock under our Revolving Credit Facility, resulting in no amounts outstanding asthe Board of December 31, 2018.Directors-authorized $750 million share repurchase program. As a result of our financing activities, we ended 20182019 with over $4.7almost $4.5 billion in liquidity, including $4.0 billion of availability under our Noble Energy Revolving Credit Facility.
As of December 31, 2018,2019 Significant Financing Highlights
initiated a commercial paper program;
issued and redeemed notes, lowering interest expense and extending debt maturities;
established a new Noble Midstream Partners term loan;
increased the Noble Midstream Services Revolving Credit Facility capacity to almost $1.2 billion;
secured a $200 million preferred equity commitment at Noble Midstream Partners; and
completed our outstanding long-term debt, net of unamortized discountmidstream asset sale and debt issuance costs and excluding capital lease obligations, totaled $6.4 billion. We may periodically seeksimplification to access the capital markets to refinance a portion of our outstanding indebtedness. In addition, we may from time to time seek to retire or purchase our outstanding senior notes through cash purchases in the open market, privately negotiated transactions or otherwise. Such activities, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors.Noble Midstream Partners.
Sources and Uses ofAvailable Liquidity
Our operating cash flows are a significant source of liquidity. For most of 2018, we experienced strengthening crude oil and NGL prices and completed several divestitures which continued the transformation strategy started in 2017, repositioning our US portfolio to high margin onshore crude oil-rich assets. These activities significantly contributed to the funding of our capital program. Additional sources of funding were available through debt financing activities, including borrowings under our Revolving Credit Facility. At the same time, we focused efforts on shareholder return initiatives, including share repurchases and dividends. Additionally, we redeemed $379 million in outstanding senior notes and repaid $230 million of outstanding 2017 borrowings on our Revolving Credit Facility.
as described above. Overall, we expect to support our 20192020 capital investment program with cash flows from operations, cash on hand, proceeds from divestments of non-strategic assets, issuances of commercial paper, borrowings under our Revolving Credit Facility,Facilities, and/or other sources of funding.
We believe our current liquidity level and balance sheet, along with our ability to access the capital markets, provide flexibility and that we are well-positioned to fund our business throughout the commodity price cycle. We will continue to evaluate the commodity price environment and our level of capital spending throughout 2019.2020. A downgrade below our current investment grade rating could trigger requirements to post collateral as financial assurance of performance under certain contractual arrangements. See Item 1A. Risk Factors – Indebtedness may limit our liquidity and financial flexibility. The table below summarizes our cash, debt balances and available liquidity:liquidity. | | | | December 31, | December 31, 2019 | | December 31, 2018 |
| (millions, except percentages) | 2018 | | 2017 | | 2016 | Noble Energy Excluding Noble Midstream Partners | | Noble Midstream Partners | | Total | | Noble Energy Excluding Noble Midstream Partners | | Noble Midstream Partners | | Total |
Total Cash (1) | $ | 719 |
| | $ | 713 |
| | $ | 1,210 |
| $ | 471 |
| | $ | 13 |
| | $ | 484 |
| | $ | 707 |
| | $ | 12 |
| | $ | 719 |
|
Amount Available to be Borrowed under Revolving Credit Facility (2) | 4,000 |
| | 3,770 |
| | 4,000 |
| |
Amounts Available for Borrowing (2) | | 4,000 |
| | — |
| | 4,000 |
| | 4,000 |
| | — |
| | 4,000 |
|
| Total Liquidity | $ | 4,719 |
| | $ | 4,483 |
| | $ | 5,210 |
| $ | 4,471 |
| | $ | 13 |
| | $ | 4,484 |
| | $ | 4,707 |
| | $ | 12 |
| | $ | 4,719 |
|
| | | | | | | | | | | | | |
Total Debt (3) | $ | 6,675 |
| | $ | 6,859 |
| | $ | 7,114 |
| $ | 6,089 |
| | $ | 1,495 |
| | $ | 7,584 |
| | $ | 6,115 |
| | $ | 560 |
| | $ | 6,675 |
|
| Noble Energy Share of Equity | 10,484 |
| | 10,619 |
| | 9,600 |
| | | | | $ | 8,410 |
| | | | | | $ | 9,426 |
|
Ratio of Debt-to-Book Capital (4) | 39 | % | | 39 | % | | 43 | % | | | | | 47 | % | | | | | | 41 | % |
| |
(1) | As of December 31, 2018, totalTotal cash includes cash and cash equivalents of $11 million related to Noble Midstream Partners and $3 million of restricted cash related to amounts held for the divestiture of certain non-core acreage in the Delaware Basin and Noble Midstream Partners collateral on letters of credit. As ofat December 31, 2017, total cash includes $18 million cash of Noble Midstream Partners and $38 million of restricted cash related to the Saddle Butte Acquisition that closed first quarter 2018. As of December 31, 2016, total cash includes $57 million cash of Noble Midstream Partners, and restricted cash of $30 million related to the Delaware Basin property acquisition that closed in January 2017. |
| |
(2) | Excludes amounts available to be borrowed under the Noble Midstream Services Revolving Credit Facility, which is not available to Noble Energy for general corporate purposes. |
| |
(3) | Total debt includes capital lease obligations and excludes unamortized debt discount/premium and debt issuance costs. Additionally, it includes $560 million of Noble Midstream Partners debt as of December 31, 2018.See Item 8. Financial Statements and Supplementary Data – Note 8. Long-Term Debt |
| |
(4) | We define our ratio of debt-to-book capital as total debt (which includes long-term debt excluding unamortized discount/premium and issuance costs, the current portion of long-term debt, and short-term borrowings) divided by the sum of total debt plus Noble Energy's share of equity. |
Cash and Cash Equivalents We had approximately $716$484 million in cash and cash equivalents at December 31, 2018, primarily denominated in US dollars and invested in money market funds and short-term deposits with major financial institutions. Approximately $4562019, $383 million of this cashwhich is attributable to our foreign subsidiaries. We do not expect to incur any significant US income tax expense with respect to future repatriation of foreign cash.
Revolving Credit Facilities Noble Energy's Revolving Credit Facility of $4.0 billion unsecured revolving credit facility (Revolving Credit Facility) and the Noble Midstream Services' revolving credit facility (Noble Midstream Services Revolving Credit Facility ofFacility), which was increased from $800 million to almost $1.2 billion in fourth quarter 2019, both mature in 2023. These facilities are used to fund capital investment programs and acquisitions and may periodically provide amounts for working capital purposes. At December 31, 2018,2019, no amounts were outstanding under theNoble Energy's Revolving Credit Facility, and $60no commercial paper borrowings were outstanding, leaving the entire $4.0 billion available for borrowing. At December 31, 2019, $595 million was outstanding under the Noble Midstream Services Revolving Credit Facility, leaving$4.0 billion and $740 $555 million inof remaining availability under the respective credit facilities.availability. See Item 8. Financial Statements and Supplementary Data – Note 9.8. Long-Term Debt.
Senior Note Issuance and RedemptionIn October 2019, we issued $500 million of 3.25% senior notes due October 15, 2029 and $500 million of 4.20% senior notes due October 15, 2049. Proceeds from the issuance were used to fund the early tender offer and redemption of our $1.0 billion 4.15% notes due December 15, 2021. As a result, we paid a premium of $44 million on the extinguishment of debt and recognized a loss in fourth quarter 2019. The transactions resulted in reduced future interest costs and extended debt maturity dates.See Item 8. Financial Statements and Supplementary Data – Note 8. Long-Term Debt. Noble Midstream Services 2019 Term Loan Credit FacilityIn August 2019, Noble Midstream Services entered into a term loan agreement, which provides for a three-year senior unsecured term loan credit facility, due August 23, 2022 (2019 Noble Midstream Services Term Loan Credit Facility), that permits aggregate borrowings of up to $400 million. Proceeds from the term loan were primarily used to repay a portion of the outstanding borrowings under the Noble Midstream Services Revolving Credit Facility. See Item 8. Financial Statements and Supplementary Data – Note 8. Long-Term Debt. Noble Midstream Services 2018 Term Loan Credit Facility In July 2018, Noble Midstream Services entered into thea term loan agreement, which provides for a three-year senior unsecured term loan credit facility, due July 31, 2021 (2018 Noble Midstream Services Term Loan Credit FacilityFacility), that permits aggregate borrowings of up to $500 million. As of December 31, 2018,2019, $500 million was outstanding under this facility, which was used to repay amounts outstanding under the Noble Midstream Services Revolving Credit Facility. See Item 8. Financial Statements and Supplementary Data – Note 9.8. Long-Term Debt. Leviathan Term Loan Facility Mezzanine Equity CommitmentThe facility, which providedIn March 2019, Noble Midstream Partners obtained a $200 million preferred equity commitment. $100 million of the commitment funded immediately and the remaining $100 million is available for a limited recourse secured loan facility with an aggregate principal borrowing amountfunding until March 2020, subject to certain conditions precedent. See Item 8. Financial Statements and Supplementary Data – Note1. Summary of upSignificant Accounting Policies.Asset Sale to $1.0Noble Midstream Partners We received approximately $1.6 billion in consideration from the sale of substantially all of our remaining midstream interests and assets to Noble Midstream Partners. Consideration included approximately $670 million in cash, of which $625$420 million was initially committed,funded by the Noble Midstream Services Revolving Credit Facility and approximately $250 million was terminated in December 2018. No amounts were ever drawn on this facility.funded by a private placement of Noble Midstream Partners common units. See Note 4. Acquisitions and Divestitures. Cash Flows
The following table summarizes our net cash flows from operating, investing and financing activities: | | | | | Year Ended December 31, | Year Ended December 31, |
| (millions) | | 2018 | | 2017 | | 2016 | 2019 | | 2018 |
| Total Cash Provided By (Used in) | | | | | | | | | |
| Operating Activities | | $ | 2,336 |
| | $ | 1,951 |
| | $ | 1,351 |
| $ | 1,998 |
| | $ | 2,336 |
|
| Investing Activities | | (1,931 | ) | | (1,617 | ) | | (401 | ) | (3,138 | ) | | (1,931 | ) |
| Financing Activities | | (399 | ) | | (831 | ) | | (768 | ) | 905 |
| | (399 | ) |
| Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash | | $ | 6 |
| | $ | (497 | ) | | $ | 182 |
| $ | (235 | ) | | $ | 6 |
|
Operating Activities In 2018, netThe decrease in cash provided by operating activities increased asin 2019 compared with 2017,2018 was primarily driven by a decrease in revenues resulting from an increase in net revenues due to rising crude oil and NGLlower commodity prices, partially offset by higherincreases in sales volumes and lower production costs attributable to increased operational activity and rising costs in US onshore, and a decrease in US natural gas sales volumes.cost saving initiatives. In addition, we madereceived cash settlements of $161commodity derivative instruments for $32 million for commodity derivatives, asin 2019, compared with cash receiptspayments of $13$161 million in the prior year2018 and we made cash interest payments related to outstanding debt of $310 million in 2019 compared with $343 million asin 2018.
Investing ActivitiesIncreases in cash used in investing activities primarily related to funding of new equity method investments of $799 million in 2019 compared with $394zero in 2018 and reduced divestiture activity resulting in proceeds from divestitures of $173 million in 2017.
Working capital changes resulted in a $47 million operating cash flow decrease in 2018 as2019 compared with a $150 million operating cash flow decrease$2.0 billion in 2017. The changes in working capital2018. These amounts were primarily due to an increase in our trade payables for drilling and development costs and midstream capital expenditures and decrease in accounts receivable. The increase was partially offset by the increasecash used in non-current assets, specifically the customer-related intangible asset recordedacquisitions of $653 million in 2018, compared to none in 2019, as part of the Saddle Butte Acquisitionwell as a $755 million decrease in first quarter 2018.spending on property, plant and equipment driven by our focus on improving cost structure and capital efficiencies during 2019, lower investment in
In 2017, net cash provided by operating activities increased as compared with 2016. The changemidstream infrastructure, and the timing of Leviathan field development costs, which were lower in cash flows from operating activities was primarily2019 than the resultpeak year of higher average realized commodity prices partially offset by lower sales volumes as a result of the Marcellus Shale upstream divestiture and lower settlements of commodity derivative instruments. The increasecapital investment in cash flows from sales was offset by the decrease in settlement proceeds from our commodity derivative instruments. The decrease in cash received from derivative settlements is reflective of an increase in the commodity prices as crude oil and natural gas prices strengthened in the second half of 2017. In 2017, we made cash interest payments related to outstanding debt of $394 million as compared with $412 million in 2016.
Investing Activities In 2018, capital spending for additions to property, plant and equipment, excluding acquisitions, totaled $3.3 billion as compared with $2.6 billion in 2017. The increase was primarily due to increased development spending for the Delaware Basin, Leviathan Phase 1 and midstream infrastructure. This was partially offset by decreased development spending in the Eagle Ford Shale and on the Marcellus Shale upstream assets and Gulf of Mexico assets following their respective sales. In addition, $653 million was spent on acquisitions during 2018.
Capital expenditures in 2017 were $2.6 billion, or $1.1 billion higher than capital spent in 2016. Approximately $700 million of the increase was due to increased US onshore development activity in response to a more favorable commodity price environment, as well as our focus on development of high margin areas in the DJ and Delaware Basins, and approximately $416 million of the increase was related to the initial Leviathan project development.
In 2016, capital spending for property, plant and equipment was $1.5 billion, or nearly half of capital spent in 2015, due to the timing of completion of major project development activities in the Gulf of Mexico, DJ Basin and Marcellus Shale. We received $1.2 billion of proceeds from asset divestitures, as compared with $151 million of proceeds from divestitures during 2015.
Financing Activities In 2018, our primaryIncreases in cash provided by financing activities included a $230include net borrowings of $535 million net, Revolving Credit Facility repayment and a $25 million, net,in 2019 on the Noble Midstream Services Revolving Credit Facility, repayment, which included borrowingscompared with net repayments of $475$25 million primarily used to fund an acquisition, offset by a repayment of $500 million drawnin 2018, and having no net repayments under the Noble Midstream Services Term LoanRevolving Credit Facility. We also usedFacility in 2019 compared with $230 million in 2018. Additionally, repayments of senior notes, net of proceeds from senior note issuances, was $53 million in 2019 compared with $384 million of cash to redeem senior notes, for which payment of accrued interest of $11 million is reflectedrepayments in operating activities.
2018. In addition, we used cash of $295 million pursuant to our share repurchase program and paid $208 million of cash dividends to Noble Energy shareholders and $51 million of cash distributions to2019, Noble Midstream Partners noncontrolling interest owners. We also received $353 million of contributions from noncontrolling interest owners. Other financing activities used net cash of $110 million.
In 2017, our primary financing activities included $230 million net Revolving Credit Facility borrowings (including the borrowing and repayment of $1.3 billion associated with the Clayton Williams Energy Acquisition), $85 million, net, Noble Midstream Services Revolving Credit Facility borrowings used primarily to fund an acquisition, a $1.1 billion senior note refinancing, $595 million related to the repayment of Clayton Williams Energy debt, and a $550 million Term Loan Facility repayment. In addition, we received $312 million net proceeds of $243 million from the issuance of Noble Midstream Partners common units, paid $190 million of cash dividends and $28 million of cash distributions, and made $60 million of capital lease principal payments.
We also received $10 million cash proceeds from the exercise of stock options and purchased 1,031,000 shares of treasury stock with a value of $36 million. These shares included 719,849 shares with a value of $25 million relatedwhich was used to vesting of Clayton Williams Energy restricted stock and options in connection with the Clayton Williams Energy Acquisition. The remaining shares were surrendered for the payment of withholding taxes due on the vesting of employee restricted stock awards.
In 2016, we used Term Loan Facility proceeds of $1.4 billion to redeem $1.4 billion of senior notes. We subsequently repaid $850 million of the Term Loan Facility from cash on hand. We received $299 million net proceeds from the issuance offund Noble Midstream Partners common unitsPartners' acquisition of our remaining midstream assets. We did not repurchase shares under our share repurchase program in a public offering. We also used cash to pay dividends on our common stock2019, compared with spending of $172 million. $295 million in 2018. In 2019, we received contributions from noncontrolling interest owners of $37 million compared with $353 million in 2018.
Acquisition Capital Expenditures and Other ExplorationCapital Expenditures
Our capital expenditures (on an accrual basis) were as follows: | | | | | Year Ended December 31, | Year Ended December 31, |
| (millions) | | 2018 | | 2017 | | 2016 | 2019 | | 2018 |
| Acquisition, Capital and Exploration Expenditures | | |
| | |
| | | |
Unproved Property Acquisition (1) | | $ | 41 |
| | $ | 1,817 |
| | $ | 234 |
| $ | 37 |
| | $ | 41 |
|
Proved Property Acquisition (2) | | — |
| | 839 |
| | — |
| |
| Exploration and Development | | 2,683 |
| | 2,352 |
| | 1,239 |
| |
| Proved Property Acquisition | | 4 |
| | — |
|
| Exploration | | 38 |
| | 25 |
|
| Development | | 2,074 |
| | 2,658 |
|
Midstream (3) | | 727 |
| | 480 |
| | 42 |
| 230 |
| | 727 |
|
| Corporate | | 60 |
| | 34 |
| | 50 |
| 66 |
| | 60 |
|
| Total | | $ | 3,511 |
| | $ | 5,522 |
| | $ | 1,565 |
| $ | 2,449 |
| | $ | 3,511 |
|
| | | |
| | |
Additions to Equity Method Investments(2) | | | | |
| EMED Pipeline B.V. | | $ | 189 |
| | $ | — |
|
| EPIC Y-Grade | | 174 |
| | — |
|
| EPIC Crude Holdings | | 358 |
| | — |
|
| Delaware Crossing | | 72 |
| | — |
|
| Other | | |
| | | | |
| 6 |
| | — |
|
Investment in Equity Method Investee (4) | | $ | — |
| | $ | 68 |
| | $ | 8 |
| |
| Increase in Capital Lease Obligations | | 14 |
| | — |
| | 5 |
| |
| Total Additions to Equity Method Investments | | $ | 799 |
| | $ | — |
|
| | | | | |
| Increase in Finance Lease Obligations | | $ | 7 |
| | $ | 14 |
|
| |
(1) | 2018 costsAmounts relate to US onshore undeveloped leasehold activity. |
2017 costs include $1.6 billion related to the Clayton Williams Energy Acquisition and $246 million related to acquisitions in the Delaware Basin.
2016 costs relate to properties exchanged upon termination of the Marcellus Shale joint development agreement.
| |
(2) | 2017 costsAmounts include $722 millioncapitalized interest that will be amortized into earnings over the useful life of proved properties and $63 million of ARO acquired in the Clayton Williams Energy Acquisition and $58 million of proved properties acquired in the Delaware Basin. |
| |
(3)
| Midstream expenditures include those of Noble Midstream Partners.related assets. |
Development costs decreased in 2019 as compared with 2018 includesdue to our focus on US onshore capital efficiencies and near-term completion of the Leviathan development activities. Costs include approximately $1.6 billion for US onshore and $482 million for Eastern Mediterranean, primarily related to Leviathan.
Midstream costs incurred in 2018 primarily relate to constructing the Mustang IDP gathering system and Delaware Basin CGFs and were higher than 2019 costs which included expansion of existing infrastructure. In addition, midstream expenditures for 2018 included $206 million related to the Saddle Butte Acquisition.
2017 includes gathering and processing assets of $48 million related to the Clayton Williams Energy Acquisition.
| |
(4)
| 2017 includes our contribution to the Advantage Pipeline joint venture, in which Noble Midstream Partners owns a 50% interest. |
Exploration and development costs increased in 2018 as compared with 2017, primarily due to increased US onshore and Leviathan development activities. Exploration and development costs include approximately $2.0 billion for US onshore and approximately $676 million for Eastern Mediterranean activities primarily related to Leviathan. In addition, Midstream capital spending, exclusive of acquisitions, increased in 2018 due to the construction of gathering systems in the DJ and Delaware Basins.acquisition.
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, 2018,2019, material off-balance sheet arrangements and transactions that we have entered into included drilling rig contracts, transportation and gathering agreements, operating lease agreements, and undrawn letters of credit and guarantees, all of which are customary in the oil and gas industry (see cross references to the Notes to the Financial Statements in the table below). Other than these aforementioned arrangements, we have no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our financial condition, results of operations, liquidity or availability of or requirements for capital resources. See Contractual Obligations, below.
Contractual Obligations
The following table summarizes certain contractual obligations as of December 31, 20182019 that are reflected in the consolidated balance sheets and/or disclosed in the accompanying notes. Unless otherwise noted, all amounts are undiscounted and are net to our interest.
| | | (millions) | Note
Reference (1) | Total | | 2019 | | 2020 and 2021 | | 2022 and 2023 | | 2024 and beyond | Note Reference (1) | 2020 | | 2021 and 2022 | | 2023 and 2024 | | 2025 and beyond | | Total |
Long-Term Debt (2) | | $ | 6,452 |
| | $ | — |
| | $ | 1,500 |
| | $ | 160 |
| | $ | 4,792 |
| | $ | — |
| | $ | 900 |
| | $ | 1,345 |
| | $ | 5,134 |
| | $ | 7,379 |
|
Interest Payments (3) | | 5,490 |
| | 295 |
| | 589 |
| | 505 |
| | 4,101 |
| |
Capital Lease Obligations (4) | | 275 |
| | 52 |
| | 77 |
| | 42 |
| | 104 |
| |
Purchase and Service Obligations (5) | | 271 |
| | 197 |
| | 42 |
| | 27 |
| | 5 |
| |
Marcellus Shale Firm Transportation and Other Obligations (6) | | 1,531 |
| | 123 |
| | 243 |
| | 231 |
| | 934 |
| |
Long-Term Debt Interest Payments and Revolving Credit Facility Commitment Fee (3) | | | 342 |
| | 661 |
| | 580 |
| | 4,458 |
| | 6,041 |
|
Operating Lease Obligations (4) | | | 100 |
| | 101 |
| | 41 |
| | 37 |
| | 279 |
|
Finance Lease Obligations (4) | | | 52 |
| | 65 |
| | 44 |
| | 86 |
| | 247 |
|
Marcellus Shale Firm Transportation Obligations (5) | | | 143 |
| | 187 |
| | 175 |
| | 675 |
| | 1,180 |
|
Purchase and Service Obligations (6) | | | 135 |
| | 42 |
| | 32 |
| | 72 |
| | 281 |
|
| Gathering, Transportation and Processing Obligations | | 801 |
| | 151 |
| | 232 |
| | 133 |
| | 285 |
| | 174 |
| | 332 |
| | 302 |
| | 334 |
| | 1,142 |
|
Operating Lease Obligations (7) | | 512 |
| | 91 |
| | 133 |
| | 112 |
| | 176 |
| |
Other Liabilities (8)(7) | | | | | | | | | | | | | | | | | | | | |
Asset Retirement Obligations (9)(8) | | 880 |
| | 118 |
| | 147 |
| | 67 |
| | 548 |
| | 85 |
| | 170 |
| | 34 |
| | 525 |
| | 814 |
|
Commodity Derivative Instruments (10) | | 27 |
| | 1 |
| | 26 |
| | — |
| | — |
| |
Commodity Derivative Instruments (9) | | | 36 |
| | 1 |
| | — |
| | — |
| | 37 |
|
| Total Contractual Obligations | | $ | 16,239 |
| | $ | 1,028 |
| | $ | 2,989 |
| | $ | 1,277 |
| | $ | 10,945 |
| | $ | 1,067 |
| | $ | 2,459 |
| | $ | 2,553 |
| | $ | 11,321 |
| | $ | 17,400 |
|
| |
(2) | Long-term debt includes our revolving credit facilities and fixed-rate debt and excludes unamortized discounts, premiums, debt issuance costs and capitalfinance lease obligations. |
| |
(3) | Interest payments and commitment fees are based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2018.2019. |
| |
(4) | Annual capital lease payments exclude regular maintenance and operational costs. |
| |
(5) | Amount includes firm transportation exit cost accruals resulting from certain permanent capacity assignments. |
| |
(6) | Purchase and service obligations represent contractual agreements to purchase goods or services that are enforceable, are legally binding and specify all significant terms, including fixed and minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. |
| |
(6)
| Amount includes exit cost obligations resulting from a permanent capacity assignment. In addition, we entered into a permanent capacity assignment in January 2019 which reduced the undiscounted financial commitment by approximately $350 million. |
| |
(7) | Operating lease obligations represent non-cancelable leases for office buildings, facilities and equipment used in our daily operations, such as drilling rigs, vessels and compressors. Annual lease payments exclude regular maintenance and operational costs. |
| |
(9)(8)
| AROs are discounted. |
| |
(10)(9)
| Amount represents commodity derivative instruments that were in a net payable position with the counterparty at December 31, 2018.2019. |
Additional contractual commitments are as follows:
Exploration CommitmentsThe terms of some of our PSCs, licenses or concession agreements may require us to conduct certain exploration activities, including drilling one or more exploratory wells or acquiring seismic data, within specific time periods. These obligations can extend over several years, and failure to conduct such exploration activities within the prescribed periods could lead to loss of leases or exploration rights and/or penalty payments.
Continuous Development Obligations Certain of our US onshore assets, such as our Eagle Ford Shale and Delaware Basin properties are primarily held through continuous development obligations. Therefore, we are contractually obligated to fund a level of development activity in these areas which could be substantial, or exercise options with land owners to extend leases. Failure to meet these obligations may result in the loss of leases.
Leviathan Natural Gas ProjectMezzanine Equity Commitment Preferred equity is perpetual and has a 6.5% annual dividend rate. The initial developmentpreferred equity partner can request redemption at a pre-determined base return following the later of the Leviathan field requires substantial infrastructure and capital; therefore, we have executed major equipment and installation contractssixth anniversary of the preferred equity closing in supportMarch 2019 or the fifth anniversary of these activities. Asthe completion date of December 31, 2018, we had entered into approximately $176 million, net, of contracts to support the remaining development activities and bring first production online by the end of 2019.EPIC Crude Oil Pipeline.
OIL Contingency As of December 31, 2018, we2019, approximately $22 million was accrued approximately $28 million for an insurance contingency due toas a theoretical withdrawal premium associated with 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,OIL and the potential termination fee is calculated annually based on OIL’s past losses, and the liability reflecting this potential charge has been accrued as of December 31, 2018.losses.
Letters of CreditIn the ordinary course of business, we maintain letters of credit and bank guarantees with a variety of banks in support of certain performance obligations of our subsidiaries. Outstanding letters of credit and bank guarantees, including Noble Midstream Partners, totaled approximately $89$132 million at December 31, 2018.2019.
Ratings Triggers We do not have triggers on any of our corporate debt that would cause an event of default in the case of a downgrade of our credit rating. See Item 1A. Risk Factors - Indebtedness may limit our liquidity and financial flexibility. CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of the consolidated financial statements requires our management to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the period. When alternatives exist among various accounting methods, the choice of accounting method can have a significant impact on reported amounts. The following is a discussion of the accounting policies, estimates and judgments which management believes are most significant in the application of US GAAP used in the preparation of the consolidated financial statements.
Reserves
Description We estimate proved oil and gas reserves according to the definition of proved reserves provided by the SEC and the Financial Accounting Standards Board (FASB). Reserves estimates have a significant impact on our financial statements as they are used as an input in the calculation of DD&A expense and in impairment assessments for crude oil and natural gas properties and goodwill.properties.
Judgment and Uncertainties The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Commodity prices and development and production costs are factors used in determining reserves economics and reserves estimates. As a result, our reserves estimates will change in the future due to commodity price volatility and cost changes, as well as due to new information obtained from development drilling and production history.
Effect if Actual Results Differ from Assumptions Our reserves estimates are based on year-endyear end cost, development, and production data and on historical 12-month average commodity price data. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserves estimates are often different from the quantities of crude oil, NGLs and natural gas that are ultimately recovered due to reservoir performance and new geological and geophysical data. Additionally, increases in future drilling, development, production and abandonment costs and changes in commodity prices may result in future revisions to our reserves.
Estimates of proved crude oil, NGL 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. For 2018,2019, a 10% reduction in estimates of proved reserves across all properties would have increased DD&A expense by approximately $190$229 million.
Oil and Gas Properties – Successful Efforts Method of Accounting
Description We account for crude oil and natural gas properties under the successful efforts method of accounting which results in the capitalization of costs directly related to specific oil and gas reserves when results are positive and expensing of certain costs, including geological and geophysical costs and delay rentals, during the periods the costs are incurred, and, in the case of dry hole costs, in the period the well is deemed non-commercial.
The alternative method of accounting for crude oil and natural gas properties is the full cost method under which 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, capitalized costs are accumulated in pools on a country-by-country basis. DD&A is computed on a country-by-country basis, and capitalized costs are limited on the same basis through the application of a ceiling test.
Judgment and Uncertainties The determination of the carrying value of our oil and gas properties includes assessment of impairment and the calculation of amortizationDD&A expense.
In determining whether unproved crude We assess our oil and natural gas properties for possible impairment whenever events or circumstances indicate that the carrying value of the asset may not be recoverable. Our assessment involves a high degree of estimation uncertainty as it requires us to make assumptions and apply judgment to estimate future net undiscounted cash flows related to proved reserves. Such assumptions include commodity prices, capital spending, production and abandonment costs and reservoir data. In cases where unproved reserve cash flows are impaired,utilized to assess properties for impairment, we apply the same pricing, cost and future production assumptions. We also apply significant judgment in assessing entity-specific assumptions and assumptions relatedrelating, but not limited to, the future economic environment, as well as potential impacts of the political and regulatory climate on future development activity. We also consider numerous factors including, but not limited to,activity, 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 forof the property.
In addition, impairment assessment involves a high degree Negative revisions in estimates of estimation uncertainty as it requires us to make assumptions and apply judgment to estimate future cash flows related to both proved and unproved reserves. Such assumptions includereserves quantities, expectations of decreasing commodity prices, capital spending, production and abandonment costs and reservoir data. Significant judgment is involved inor rising
estimating these factors,operating or development costs could result in a reduction in undiscounted future cash flows, potentially indicating an impairment.
An impairment is indicated if, as a result of the assessment, an asset's carrying value exceeds its future net undiscounted cash flows. Once an impairment is indicated, we estimate the asset's fair value as the carrying value of the asset may not be recoverable. In the absence of comparable market data, fair value is estimated using a discounted net cash flow model. Cash flows are discounted using a risk-adjusted rate and they include uncertainties. In cases where probable and possible reservescompared to the carrying value in determining the amount of impairment expense to record. Estimated future cash flows are utilized to assess propertiesbased on management’s expectations for impairment, we use the same pricing, costfuture and include estimates of crude oil, natural gas and NGL reserves and future production assumptions. commodity prices, revenues and operating and development costs.
For the purpose of impairment testingassessment as of December 31, 2018, we used2019, the undiscounted future net cash flows included five-year strip prices for crude oil and natural gas, with prices subsequent to the fifth year held constant as the benchmark price, unless contractual arrangements designatedesignated the price to be used, in the undiscounted future net cash flows.used. Capital and operating costs were estimated assuming 0% escalation. As a result of the assessment, an impairment of our Eagle Ford Shale assets was indicated. We then estimated the fair value of the assets and reduced the carrying value of the assets to fair value, resulting in impairment expense of $1.2 billion. See Item 8. Financial Statements and Supplementary Data – Note 10. Impairments. For capitalized exploratory well costs, significant judgment is required in order to determine whether sufficient progress has been made in assessing the reserves and the economic and operational viability of a project in order to continue capitalization of such costs. Such assessment requires consideration of the following factors: commitment of project personnel, costs incurred to assess reserves and potential development, progress of economic, legal, political and environmental aspects of potential development, existence or active negotiations of agreements with governments and venture partners or sales contracts with customers, identification of existing transportation and other infrastructure that is or will be available for the project and other factors. Consideration of these factors requires us to make assumptions and apply judgment to assess industry and economic conditions, as well as our future drilling and development plans. Future changes in our exploratory and drilling activities or economic conditions may result in the determination not to pursue certain projects, resulting in future write-offs of the capitalized exploratory well costs.
Calculation of unit-of-production rates for DD&A purposes is performed on a field-by-field basis and includes estimation of the period-end reserves base and production data for each respective field, including estimates of production for non-operated properties.
Effect if Actual Results Differ from Assumptions At year-end,year end, the net book value of our unproved properties includes significant amounts allocated in previous business combinations or acquisitions. Unfavorable revisions to our reserves and/or changes in our exploration and development plans or the economic, political or regulatory environment in areas where we operate, or changes in the availability of funds for future activities may result in abandonment and impairment of unproved leases and oil and gas properties. Unfavorable changes in pricing and cost assumptions in the future may result in negative revisions to proved and/or unproved reserves and associated cash flows, causing us to record impairment of proved and/or unproved oil and gas properties. An impairment of a proved or unproved property could result in a significant decrease in earnings.
If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs would be charged to exploration expense in future periods, resulting in a decrease in earnings. See Item 8. Financial Statements and Supplementary Data – Note 7.6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs. Furthermore, a change in groupings of our oil and gas properties for the purpose of the DD&A calculation and impairment review could affect the calculation of unit-of-production rates, DD&A expense and determination of impairment.
Purchase Price Allocations and Resulting Goodwill
DescriptionWe use the acquisition method to account for certain business combinations. This method requires us to allocate the acquisition cost to assets acquired and liabilities assumed based on fair values as of the acquisition date, with any difference recorded either as goodwill or 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. Any goodwill recognized is subsequently assessed for impairment through an initial qualitative assessment, followed by the application of the quantitative test.
Judgment and Uncertainties Estimation of the fair values of assets acquired and liabilities assumed in a business combination requires that we make various assumptions, the most significant of which relate to the estimated fair values assigned to proved and unproved crude oil and natural gas properties. In most cases, sufficient market data is not available regarding the fair values of proved and unproved properties, and we prepare estimates of such properties based on the fair value of associated crude oil, NGL and natural gas reserves utilizing the income approach. The primary assumptions used to arrive at estimates of future net cash flows used in the income approach include reserves quantities, future commodity prices, and capital and operating costs. For estimated proved reserves, the future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted average cost of capital rate is subjected to additional project-specific risk 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 that, in management's judgment, are reasonable.
For other assets acquired in business combinations, we use judgment to determine the appropriate combination of available cost and market data and/or estimated cash flows to determine the fair values. 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.
The initial qualitative goodwill impairment assessment also involves significant judgment, as we are required to examine relevant events and circumstances which could have a negative impact on our goodwill, such as: macroeconomic conditions; industry and market conditions, including commodity prices; cost factors; overall financial performance; reporting unit dispositions and acquisitions; and other relevant entity-specific events.
Management must make estimates regarding the fair value of the reporting unit to which goodwill has been assigned. We use a combination of the income and market approaches to determine the fair value of a reporting entity. These approaches result in fair values that are subject to a high degree of estimation uncertainty as they require us to make assumptions and apply judgment to various parameters that are sensitive to industry, market and economic conditions. Inputs for the income approach include estimates of both proved reserves and risk-adjusted unproved reserves; market prices considering forward commodity price curves as of the measurement date; and operating, administrative and capital costs adjusted for inflation. Inputs for the market approach include selection of comparable companies and/or comparable recent company and asset transactions and transaction premiums as well as selected company financial metrics, such as EBITDAX.
Effect if Actual Results Differ from Assumptions Although we based the fair value estimate of the US reporting unit on assumptions we believed to be reasonable, those assumptions were inherently unpredictable and uncertain. Changes in assumptions, such as an increase in commodity prices or a decrease in discount rates, could have resulted in a lesser amount of impairment or no goodwill impairment at all. For example, we conducted our annual goodwill impairment assessment, concluding that the goodwill allocated to the Texas reporting unit was fully impaired. See Item 8. Financial Statements and Supplementary Data – Note 6. Goodwill Impairment.The estimated fair values assigned to assets acquired and liabilities assumed in a purchase price allocation can have a significant effect on future results of operations. For example, a higher fair value assigned to a property results in higher DD&A expense, which results in lower net income. In addition, 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 the estimates originally used to determine fair value, the resulting reductions in future cash flows could indicate that a property is impaired.
In addition, the estimates used in our goodwill impairment test do not constitute forecasts or projections of future results of operations, but are rather estimates and assumptions based on historical results and assessments of macroeconomic factors as of the valuation date. We believe that our estimates and assumptions are reasonable, but they are subject to change from period to period. Actual results of operations and other factors will likely differ from the estimates used in our discounted cash flow valuation and it is possible that differences could be material. In the event of a prolonged industry downturn, commodity prices could again become depressed or decline, thereby causing the fair values of our reporting units to decline, which could result in an impairment of goodwill. A property or goodwill 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.
If, in the future, we dispose of a reporting unit or a portion of a reporting unit that constitutes a business, we will include goodwill associated with that business in the carrying amount of the business in order to determine the gain or loss on disposal. The amount of goodwill allocated to the carrying amount of a business can significantly impact the amount of gain or loss recognized on the sale of that business.
Exit Costs
Description Our consolidated balance sheets include accrued exit cost liabilities relating to retained Marcellus Shale natural gas firm transportation contracts.
Judgment and Uncertainties We are required to make significant judgments and estimates regarding the timing and amount of recognition of exit cost liabilities, taking into consideration current commercialization activities related to the retained firm transportation contracts and/or the potential occurrence of a cease-use date. We must consider, among other factors, the status of negotiations with counterparties regarding permanent assignment or capacity release of our contract commitments and the likelihood of capacity utilization through purchase of third-party natural gas, which would reducereduces unutilized volume commitments.
Additionally, any subsequent changes in interest rates and/or credit risk will affect the discount rate used to calculate the present value of expected future cash flows associated with our existing contract commitments.
There are inherent uncertainties surrounding the recording of exit cost liabilities, and, in future periods, a number of factors could significantly change our estimate of such obligations or result in recognition of additional liability.
Effect if Actual Results Differ from Assumptions Although we based the initial fair value estimate of our accrued exit cost liabilities on assumptions we believed to be reasonable, those assumptions were inherently unpredictable and uncertain. Changes in assumptions, such as a reduced likelihood of capacity utilization through purchase of third-party natural gas, could have resulted in a higher exit cost accrual, higher current period expense, and lower future expense. For example, as of December 31, 2018,2019, we have a significant remaining financial commitment associated with Marcellus Shale firm transportationretained contracts. We cannot guarantee that our current commercialization efforts for these contracts will be successful, and, in the
Income Tax Expense and Deferred Tax Assets
Description Our consolidated balance sheets include deferred tax assets and liabilities relating to temporary differences, operating losses, and tax-credit carryforwards. Valuation allowances may reduce the deferred tax assets if it is more likely than not that some portion or all of the deferred tax assets will not be realized.
Judgment and Uncertainties Estimates of amounts of income tax to be recorded involve interpretation of complex tax laws as well as assessment of the effects of foreign taxes on domestic taxes, and estimates regarding the timing and amounts of future repatriation of earnings from controlled foreign corporations.
In determining whether a valuation allowance is required for our deferred tax asset balances, we consider all available evidence (both positive and negative) including, among other factors, current financial position, results of operations, projected future taxable income, tax planning strategies and new tax legislation. Significant judgment is involved in this determination as we are required to make assumptions about future commodity prices, projected production rates, timing of development activities, profitability of future business strategies and forecasted economics in the oil and gas industry. Judgment is also required in considering the relative weight of negative and positive evidence. Additionally, changes in the effective tax rate resulting from changes in tax law and our level of earnings may limit utilization of deferred tax assets and will affect valuation of deferred tax balances in the future.
Effect if Actual Results Differ from Assumptions 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. Changes to our current financial position, results of operations, projected future taxable income, tax planning strategies and/or new tax legislation may be deemed significant enough to necessitate a change to our deferred tax asset valuation allowances in the future, in which case the increases or decreases could significantly impact net income through offsetting changes in income tax expense. See Item 8. Financial Statements and Supplementary Data – Note 12.13. Income Taxes. Item 7A. 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 gascommodity prices continues to impact the oil and gas industry.
Derivative Instruments Held for Non-Trading Purposes Due to commodity price volatility, we may use derivative instruments as a means of managing our exposure to price changes.
At December 31, 2018,2019, we had various open commodity derivative instruments related to crude oil and natural gas.instruments. Changes in the 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 assetliability position with a fair value of $153$22 million. Based on the December 31, 20182019 published commodity futures price curves for the underlying commodities, a hypothetical price increase of 10% per Bbl for both crude oil and NGLs and 10% per MMBtu for natural gas would decreaseincrease the fair value of our net commodity derivative assetliability by approximately $272$121 million.
Even with certain hedging arrangements in place to mitigate the effect of commodity price volatility, our 20192020 revenues and results of operations could be adversely affected if commodity prices were to decline. See Item 1A. Risk Factors – Commodity hedging transactions may limit our potential gains or fail to fully protect us from declines in commodity prices and Item 8. Financial Statements and Supplementary Data – Note 13.14. 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 December 31, 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% at December 31, 2018. 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 December 31, 2018, our cash and cash equivalents totaled $716 million, approximately 25% of which was invested in money market funds and short-term investments with major financial institutions.
In addition, issuances of commercial paperborrowings. Borrowings under our commercial paper program, and borrowings under the Revolving Credit Facility, Noble Midstream Services Revolving Credit Facility and Noble Midstream Services Term Loan Credit FacilityFacilities, which as of December 31, 2019 total $1.5 billion and have a weighted average interest rate of 2.92%, 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 amounts, if any, related to these debt agreements would have has a de minimis impact on our variable-rate debt could expose usconsolidated net loss. See Item 8. Financial Statements and Supplementary Data – Note 8. Long-Term Debt.
While we currently have no interest rate derivative instruments as of December 31, 2018,2019, we may invest in such instruments in the future in order to mitigate interest rate risk. A change in
LIBOR TransitionLondon Inter-bank Offered Rate (LIBOR) is a commonly used indicative measure of the average interest rate applicableat which major global banks could borrow from one another. Certain of our commercial agreements use LIBOR as a “benchmark” or “reference rate” for various commercial terms. It is currently expected that the LIBOR benchmark will be discontinued after 2021. We are currently reviewing our contracts that extend past 2021 to our short-term investments or amounts, if any, outstanding underdetermine their exposure to LIBOR, some of which contain an existing LIBOR alternative. Where there is not an alternative, we expect to replace the above-named facilities wouldLIBOR benchmark with an alternative reference rate such as the Secured Overnight Financing Rate. We do not expect the transition to an alternative rate to have a de minimissignificant impact on our consolidated net income. See Item 8. Financial Statements and Supplementary Data – Note 9. Long-Term Debt.business, operations or liquidity. Foreign Currency Risk
The US dollar is considered the functional currency for each of our international operations. Substantially all of our international crude oil, NGL and natural gas 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. Net transaction gains and losses were de minimis for 2019, 2018 2017 and 2016.2017.
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.
Item 8. Financial Statements and Supplementary Data
INDEX TO FINANCIAL STATEMENTS
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Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate "internal“internal control 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 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, 2018,2019, our management assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established in Internal Control – Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, management determined that we maintained effective internal control over financial reporting as of December 31, 2018,2019, based on those criteria.
KPMG LLP, the independent registered public accounting firm that audited our consolidated financial statements included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of internal control over financial reporting as of December 31, 20182019 which is included herein.
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors and Shareholders
Noble Energy, Inc.:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Noble Energy, Inc. and subsidiaries (the Company) as of December 31, 20182019 and 2017,2018, the related consolidated statements of operations and comprehensive (loss) income, (loss),cash flows, and shareholders’ equity and cash flows for each of the years in the three‑year period ended December 31, 2018,2019, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20182019 and 2017,2018, and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2018,2019, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2018,2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 19, 201912, 2020 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
Change in Accounting Principle
As discussed in Note 1 to the consolidated financial statements, the Company has changed its method of accounting for leases as of January 1, 2019 due to the adoption of Accounting Standards Update No. 2016-02, Leases.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Assessment of the impact of estimated proved oil and gas reserves on depletion expense related to producing oil and gas properties
As discussed in Note 1 to the consolidated financial statements, the Company calculates depletion expense related to producing oil and gas properties using the unit-of-production method. Under this method, capitalized costs of producing oil and gas properties, along with support equipment and facilities, are depleted to expense over proved oil and gas reserves. For the year ended December 31, 2019, the Company recorded depreciation, depletion and amortization expense of $2,197 million. The estimation of proved oil and gas reserves requires the expertise of professional petroleum reserve engineers who take into consideration forecasted production. The Company’s internal reserve engineers prepare an estimate of the proved oil and gas reserves. The Company engages external reserve engineers to independently evaluate the proved oil and gas reserves estimated by the Company.
We identified the assessment of the impact of estimated proved oil and gas reserves on depletion expense related to producing oil and gas properties as a critical audit matter. Complex auditor judgment was required in evaluating the Company’s estimate of proved oil and gas reserves, which was an input to the depletion expense calculation. Specifically, auditor judgment was required to evaluate the forecasted production of proved oil and gas reserves.
The primary procedures we performed to address this critical audit matter included the following. We tested certain internal controls over the Company’s depletion process, including controls related to the forecasted production of proved oil and gas reserves. We analyzed and recalculated the depletion expense for compliance with industry and regulatory standards. We assessed the methodology used by the Company’s internal reserve engineers to estimate proved oil and gas reserves. We assessed the competence, capabilities, and objectivity of the Company’s internal reserve engineers, who estimated the proved oil and gas reserves, and the external reserve engineers engaged by the Company. We compared the forecasted production used by the Company to historical production rates. We read the findings of the Company’s external reserve engineers in order to understand the method and assumptions used by the engineers in connection with our evaluation of the Company’s reserve estimates.
Assessment of recoverability of oil and gas properties in the Eagle Ford Shale and in the Delaware Basin
As discussed in Note 1 and 10 to the consolidated financial statements, the Company routinely assesses its oil and gas properties for impairment indicators. If an impairment indicator is identified in relation to one or more oil and gas properties, an undiscounted cash flow analysis is required to quantitatively evaluate recoverability. The Company estimates future net cash flows expected in connection with the oil and gas property and compares such future net cash flows to the carrying amount of the oil and gas property to determine if the carrying amount is recoverable. When the carrying amount of an oil and gas property exceeds its estimated undiscounted future net cash flows, the carrying amount is reduced to estimated fair value. Estimated future net cash flows used to estimate fair value are based on the Company’s forecasted production of oil and gas reserves, commodity prices based on published forward price curves or contract prices as of the date of the estimate, operating and development costs, and a discount rate. The Company recorded an impairment of $1.2 billion related to the Eagle Ford Shale proved properties and did not record any impairment related to the Delaware Basin oil and gas properties.
We identified the assessment of recoverability of oil and gas properties in the Eagle Ford Shale and in the Delaware Basin as a critical audit matter. There was a high degree of subjective auditor judgment in evaluating the key assumptions used to estimate the undiscounted future net cash flows of oil and gas properties in the Delaware Basin and the discounted future net cash flows of oil and gas properties in the Eagle Ford Shale. The key assumptions were the estimated future commodity prices, including relevant market differentials, forecasted production of oil and gas reserves, risk adjustment factors associated with oil and gas reserves, estimated future operating and development costs, and a discount rate applied to the cash flows.
The primary procedures we performed to address this critical audit matter included the following. We tested certain internal controls over the Company’s oil and gas property impairment process, including controls related to the key assumptions. We compared forecasted commodity prices to publicly available market information. We evaluated the Company’s undiscounted future net cash flows by comparing the Company’s forecasted production of oil and gas reserves, development costs, and operating costs to historical results. We evaluated risk adjustment factors against supporting information used by the Company and guideline ranges by reserve class from published industry surveys. We evaluated the competence, capabilities, and objectivity of the Company’s internal reserve engineers, who estimated the reserves, including the applicable risk adjustment factors. In addition, we involved a valuation professional with specialized skills and knowledge, who assisted in evaluating the discount rate used in the valuation, by comparing it against a discount rate range that was independently developed using publicly available market data for comparable entities.
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| | | | |
| | | /s/ KPMG LLP | | |
| | | | | |
| We have served as the Company’s auditor since 2002. |
| | | | | |
| Houston, Texas | | | | |
February 19, 201912, 2020 | | | | |
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors and Shareholders
Noble Energy, Inc.:
Opinion on Internal Control Over Financial Reporting
We have audited Noble Energy, Inc.'s andsubsidiaries’ (the Company) internal control over financial reporting as of December 31, 2018,2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018,2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 20182019 and 2017,2018, the related consolidated statements of operations and comprehensive (loss) income, (loss),cash flows, and shareholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2018,2019, and the related notes (collectively, the consolidated financial statements), and our report dated February 19, 201912, 2020 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Controls over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
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| | | | |
| | | /s/ KPMG LLP | | |
| Houston, Texas | | | | |
February 19, 201912, 2020 | | | | |
Noble Energy, Inc.
Consolidated Statements of Operations and Comprehensive (Loss) Income (Loss)
(millions, except per share amounts)
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 | 2019 | | 2018 | | 2017 |
| Revenues | | | | | | | | | | |
| Oil, NGL and Gas Sales | $ | 4,461 |
| | $ | 4,060 |
| | $ | 3,389 |
| $ | 3,904 |
| | $ | 4,461 |
| | $ | 4,060 |
|
| Sales of Purchased Oil and Gas and Other | 525 |
| | 196 |
| | 102 |
| |
| Sales of Purchased Oil and Gas | | 389 |
| | 275 |
| | — |
|
| Other Revenue | | 145 |
| | 250 |
| | 196 |
|
| Total | 4,986 |
| | 4,256 |
| | 3,491 |
| 4,438 |
| | 4,986 |
| | 4,256 |
|
| Costs and Expenses | | | | | | | | | | |
| Production Expense | 1,197 |
| | 1,141 |
| | 1,100 |
| 1,137 |
| | 1,197 |
| | 1,141 |
|
| Exploration Expense | 129 |
| | 188 |
| | 925 |
| 202 |
| | 129 |
| | 188 |
|
| Depreciation, Depletion and Amortization | 1,934 |
| | 2,053 |
| | 2,454 |
| 2,197 |
| | 1,934 |
| | 2,053 |
|
| Loss on Marcellus Shale Upstream Divestiture and Other | — |
| | 2,379 |
| | — |
| |
| General and Administrative | | 416 |
| | 385 |
| | 415 |
|
| Cost of Purchased Oil and Gas | | 431 |
| | 296 |
| | — |
|
| Gain on Divestitures, Net | (843 | ) | | (326 | ) | | (238 | ) | — |
| | (843 | ) | | (326 | ) |
| Asset Impairments | 206 |
| | 70 |
| | 92 |
| 1,160 |
| | 206 |
| | 70 |
|
| Goodwill Impairment | 1,281 |
| | — |
| | — |
| — |
| | 1,281 |
| | — |
|
| General and Administrative | 385 |
| | 415 |
| | 399 |
| |
| Loss on Marcellus Shale Upstream Divestiture and Other | | — |
| | — |
| | 2,379 |
|
| Other Operating Expense, Net | 346 |
| | 138 |
| | 135 |
| 214 |
| | 50 |
| | 138 |
|
| Total | 4,635 |
| | 6,058 |
| | 4,867 |
| 5,757 |
| | 4,635 |
| | 6,058 |
|
| Operating Income (Loss) | 351 |
| | (1,802 | ) | | (1,376 | ) | |
| Operating (Loss) Income | | (1,319 | ) | | 351 |
| | (1,802 | ) |
| Other Expense | | | | | | | | | | |
| (Gain) Loss on Commodity Derivative Instruments | (63 | ) | | (63 | ) | | 139 |
| |
| Loss (Gain) on Extinguishment of Facility or Debt | 8 |
| | 98 |
| | (80 | ) | |
| Loss (Gain) on Commodity Derivative Instruments | | 143 |
| | (63 | ) | | (63 | ) |
| Loss on Extinguishment of Debt or Facility | | 44 |
| | 8 |
| | 98 |
|
| Interest, Net of Amount Capitalized | 282 |
| | 354 |
| | 328 |
| 260 |
| | 282 |
| | 354 |
|
| Other Non-Operating (Income) Expense, Net | (16 | ) | | — |
| | 9 |
| |
| Other Non-Operating Expense (Income), Net | | 10 |
| | (16 | ) | | — |
|
| Total | 211 |
| | 389 |
| | 396 |
| 457 |
| | 211 |
| | 389 |
|
| Income (Loss) Before Income Taxes | 140 |
| | (2,191 | ) | | (1,772 | ) | |
| Income Tax Expense (Benefit) | 126 |
| | (1,141 | ) | | (787 | ) | |
| Net Income (Loss) and Comprehensive Income (Loss) Including Noncontrolling Interests | 14 |
| | (1,050 | ) | | (985 | ) | |
| (Loss) Income Before Income Taxes | | (1,776 | ) | | 140 |
| | (2,191 | ) |
| Income Tax (Benefit) Expense | | (343 | ) | | 126 |
| | (1,141 | ) |
| Net (Loss) Income and Comprehensive (Loss) Income Including Noncontrolling Interests | | (1,433 | ) | | 14 |
| | (1,050 | ) |
| Less: Net Income and Comprehensive Income Attributable to Noncontrolling Interests | 80 |
| | 68 |
| | 13 |
| 79 |
| | 80 |
| | 68 |
|
| Net Loss and Comprehensive Loss Attributable to Noble Energy | $ | (66 | ) | | $ | (1,118 | ) | | $ | (998 | ) | $ | (1,512 | ) | | $ | (66 | ) | | $ | (1,118 | ) |
| | | | | | | | | | | |
| Loss Attributable to Noble Energy per Common Share | | | | | | | | | | |
| Basic and Diluted | $ | (0.14 | ) | | $ | (2.38 | ) | | $ | (2.32 | ) | $ | (3.16 | ) | | $ | (0.14 | ) | | $ | (2.38 | ) |
| Weighted Average Number of Shares Outstanding | | | | | | | | | | |
| Basic and Diluted | 483 |
| | 469 |
| | 430 |
| 478 |
| | 483 |
| | 469 |
|
The accompanying notes are an integral part of these financial statements.
Noble Energy, Inc.
Consolidated Balance Sheets
(millions)
| | | | December 31,
2018 | | December 31,
2017 | December 31,
2019 | | December 31,
2018 |
| ASSETS | | | | | | |
| Current Assets | | | | | | |
| Cash and Cash Equivalents | $ | 716 |
| | $ | 675 |
| $ | 484 |
| | $ | 716 |
|
| Accounts Receivable, Net | 616 |
| | 748 |
| 730 |
| | 616 |
|
| Other Current Assets | 418 |
| | 780 |
| 148 |
| | 418 |
|
| Total Current Assets | 1,750 |
| | 2,203 |
| 1,362 |
| | 1,750 |
|
| Property, Plant and Equipment | | | | | | |
| Oil and Gas Properties (Successful Efforts Method of Accounting) | 29,002 |
| | 29,678 |
| 30,404 |
| | 29,002 |
|
| Property, Plant and Equipment, Other | 891 |
| | 879 |
| 1,083 |
| | 891 |
|
| Total Property, Plant and Equipment, Gross | 29,893 |
| | 30,557 |
| 31,487 |
| | 29,893 |
|
| Accumulated Depreciation, Depletion and Amortization | (11,474 | ) | | (13,055 | ) | (14,036 | ) | | (11,474 | ) |
| Total Property, Plant and Equipment, Net | 18,419 |
| | 17,502 |
| 17,451 |
| | 18,419 |
|
| Other Noncurrent Assets | 731 |
| | 461 |
| 1,834 |
| | 841 |
|
| Goodwill | 110 |
| | 1,310 |
| |
| Total Assets | $ | 21,010 |
| | $ | 21,476 |
| $ | 20,647 |
| | $ | 21,010 |
|
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | | | |
| Current Liabilities | | | | | | |
| Accounts Payable - Trade | $ | 1,207 |
| | $ | 1,161 |
| $ | 1,250 |
| | $ | 1,207 |
|
| Other Current Liabilities | 519 |
| | 578 |
| 719 |
| | 519 |
|
| Total Current Liabilities | 1,726 |
| | 1,739 |
| 1,969 |
| | 1,726 |
|
| Long-Term Debt | 6,574 |
| | 6,746 |
| 7,477 |
| | 6,574 |
|
| Deferred Income Taxes | 1,061 |
| | 1,127 |
| 662 |
| | 1,061 |
|
| Other Noncurrent Liabilities | 1,165 |
| | 1,245 |
| 1,378 |
| | 1,165 |
|
| Total Liabilities | 10,526 |
| | 10,857 |
| 11,486 |
| | 10,526 |
|
| Commitments and Contingencies | | | |
| |
|
|
| Mezzanine Equity | | | | |
| Redeemable Noncontrolling Interest, Net | | 106 |
| | — |
|
| 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; 520 Million and 529 Million Shares Issued, respectively | 5 |
| | 5 |
| |
| Common Stock - Par Value $0.01 per share; 1 Billion Shares Authorized; 522 Million and 520 Million Shares Issued, respectively | | 5 |
| | 5 |
|
| Additional Paid in Capital | 8,203 |
| | 8,438 |
| 8,927 |
| | 8,203 |
|
| Accumulated Other Comprehensive Loss | (32 | ) | | (30 | ) | (31 | ) | | (32 | ) |
| Treasury Stock, at Cost; 39 Million Shares | (730 | ) | | (725 | ) | (732 | ) | | (730 | ) |
| Retained Earnings | 1,980 |
| | 2,248 |
| 241 |
| | 1,980 |
|
| Noble Energy Share of Equity | 9,426 |
| | 9,936 |
| 8,410 |
| | 9,426 |
|
| Noncontrolling Interests | 1,058 |
| | 683 |
| 645 |
| | 1,058 |
|
| Total Equity | 10,484 |
| | 10,619 |
| |
| Total Liabilities and Equity | $ | 21,010 |
| | $ | 21,476 |
| |
| Total Shareholders' Equity | | 9,055 |
| | 10,484 |
|
| Total Liabilities, Mezzanine Equity and Shareholders' Equity | | $ | 20,647 |
| | $ | 21,010 |
|
The accompanying notes are an integral part of these financial statements.
Noble Energy, Inc.
Consolidated Statements of Cash Flows
(millions)
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 | 2019 | | 2018 | | 2017 |
| Cash Flows From Operating Activities | | | | | | | | | | |
| Net Income (Loss) Including Noncontrolling Interests | $ | 14 |
| | $ | (1,050 | ) | | $ | (985 | ) | |
| Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities | |
| | |
| | | |
| Net (Loss) Income Including Noncontrolling Interests | | $ | (1,433 | ) | | $ | 14 |
| | $ | (1,050 | ) |
| Adjustments to Reconcile Net (Loss) Income to Net Cash Provided by Operating Activities | | |
| | |
| | |
| Depreciation, Depletion and Amortization | 1,934 |
| | 2,053 |
| | 2,454 |
| 2,197 |
| | 1,934 |
| | 2,053 |
|
| Loss on Marcellus Shale Upstream Divestiture and Other | — |
| | 2,379 |
| | — |
| — |
| | — |
| | 2,379 |
|
| Gain on Divestitures, Net | (843 | ) | | (326 | ) | | (238 | ) | — |
| | (843 | ) | | (326 | ) |
| Asset Impairments | 206 |
| | 70 |
| | 92 |
| 1,160 |
| | 206 |
| | 70 |
|
| Goodwill Impairment | 1,281 |
| | — |
| | — |
| — |
| | 1,281 |
| | — |
|
| Deferred Income Tax Benefit | (70 | ) | | (1,227 | ) | | (984 | ) | (434 | ) | | (70 | ) | | (1,227 | ) |
| Loss (Gain) on Extinguishment of Facility or Debt, Net | 4 |
| | 98 |
| | (80 | ) | |
| (Gain) Loss on Commodity Derivative Instruments | (63 | ) | | (63 | ) | | 139 |
| |
| Net Cash (Paid) Received in Settlement of Commodity Derivative Instruments | (161 | ) | | 13 |
| | 569 |
| |
| Loss on Extinguishment of Debt or Facility | | 44 |
| | 4 |
| | 98 |
|
| Loss (Gain) on Commodity Derivative Instruments | | 143 |
| | (63 | ) | | (63 | ) |
| Net Cash Received (Paid) in Settlement of Commodity Derivative Instruments | | 32 |
| | (161 | ) | | 13 |
|
| Stock Based Compensation | 62 |
| | 104 |
| | 77 |
| 68 |
| | 62 |
| | 104 |
|
| Undeveloped Leasehold Impairment | 1 |
| | 62 |
| | 93 |
| |
| Dry Hole Cost | 1 |
| | 9 |
| | 579 |
| |
| Other Adjustments for Noncash Items Included in Net Income (Loss) | 17 |
| | (21 | ) | | 95 |
| |
| Firm Transportation Exit Cost | | 88 |
| | — |
| | — |
|
| Noncash Exploration Expense | | 100 |
| | 2 |
| | 71 |
|
| Other Adjustments for Noncash Items Included in Net (Loss) Income | | 98 |
| | 17 |
| | (21 | ) |
| Changes in Operating Assets and Liabilities | | | | | | | | | | |
| Decrease (Increase) in Accounts Receivable | 156 |
| | (171 | ) | | (151 | ) | |
| (Decrease) Increase in Accounts Payable | (63 | ) | | 248 |
| | (111 | ) | |
| Increase (Decrease) in Current Income Taxes Payable | 22 |
| | (36 | ) | | (32 | ) | |
| (Increase) Decrease in Accounts Receivable | | (6 | ) | | 156 |
| | (171 | ) |
| Increase (Decrease) in Accounts Payable | | 9 |
| | (63 | ) | | 248 |
|
| Other Current Assets and Liabilities, Net | (36 | ) | | (71 | ) | | (76 | ) | 94 |
| | (14 | ) | | (107 | ) |
| Other Operating Assets and Liabilities, Net | (126 | ) | | (120 | ) | | (90 | ) | (162 | ) | | (126 | ) | | (120 | ) |
| Net Cash Provided by Operating Activities | 2,336 |
| | 1,951 |
| | 1,351 |
| 1,998 |
| | 2,336 |
| | 1,951 |
|
| Cash Flows From Investing Activities | |
| | |
| | | |
| | |
| | |
| Additions to Property, Plant and Equipment | (3,279 | ) | | (2,649 | ) | | (1,541 | ) | (2,524 | ) | | (3,279 | ) | | (2,649 | ) |
| Acquisitions, Net of Cash Received | (653 | ) | | (954 | ) | | 30 |
| — |
| | (653 | ) | | (954 | ) |
| Proceeds from Divestitures | 1,999 |
| | 2,073 |
| | 1,241 |
| |
| Marcellus Shale Acreage Exchange Consideration | — |
| | — |
| | (213 | ) | |
| Additions to Equity Method Investments | | (799 | ) | | — |
| | (68 | ) |
| Net Proceeds from Divestitures | | 173 |
| | 1,999 |
| | 2,073 |
|
| Other | 2 |
| | (87 | ) | | 82 |
| 12 |
| | 2 |
| | (19 | ) |
| Net Cash Used in Investing Activities | (1,931 | ) | | (1,617 | ) | | (401 | ) | (3,138 | ) | | (1,931 | ) | | (1,617 | ) |
| Cash Flows From Financing Activities | |
| | |
| | | |
| | |
| | |
| Proceeds from Revolving Credit Facility | 1,580 |
| | 1,585 |
| | — |
| 50 |
| | 1,580 |
| | 1,585 |
|
| Repayment of Revolving Credit Facility | (1,810 | ) | | (1,355 | ) | | — |
| (50 | ) | | (1,810 | ) | | (1,355 | ) |
| Proceeds from Term Loan Facility | — |
| | — |
| | 1,400 |
| |
| Repayment of Term Loan Facility | — |
| | (550 | ) | | (850 | ) | — |
| | — |
| | (550 | ) |
| Proceeds from Noble Midstream Services Revolving Credit Facility | 777 |
| | 325 |
| | — |
| 1,290 |
| | 777 |
| | 325 |
|
| Repayment of Noble Midstream Services Revolving Credit Facility | (802 | ) | | (240 | ) | | — |
| (755 | ) | | (802 | ) | | (240 | ) |
| Proceeds from Noble Midstream Services Term Loan Credit Facility | 500 |
| | — |
| | — |
| |
| Proceeds from Noble Midstream Services Term Loan Credit Facilities | | 400 |
| | 500 |
| | — |
|
| Repayment of Senior Notes | (384 | ) | | (1,114 | ) | | (1,383 | ) | (1,053 | ) | | (384 | ) | | (1,114 | ) |
| Repayment of Clayton Williams Energy Long-term Debt | — |
| | (595 | ) | | — |
| — |
| | — |
| | (595 | ) |
| Proceeds from Issuance of Senior Notes | — |
| | 1,086 |
| | — |
| 1,000 |
| | — |
| | 1,086 |
|
| Dividends Paid, Common Stock | (208 | ) | | (190 | ) | | (172 | ) | (227 | ) | | (208 | ) | | (190 | ) |
| Purchase and Retirement of Common Stock | (295 | ) | | — |
| | — |
| — |
| | (295 | ) | | — |
|
| Proceeds from Issuance of Mezzanine Equity, Net of Offering Costs | | 97 |
| | — |
| | — |
|
| Issuance of Noble Midstream Partners Common Units, Net of Offering Costs | — |
| | 312 |
| | 299 |
| 243 |
| | — |
| | 312 |
|
| Contributions from Noncontrolling Interest Owners | 353 |
| | 19 |
| | — |
| 37 |
| | 353 |
| | 19 |
|
| Other | (110 | ) | | (114 | ) | | (62 | ) | (127 | ) | | (110 | ) | | (114 | ) |
| Net Cash Used in Financing Activities | (399 | ) | | (831 | ) | | (768 | ) | 905 |
| | (399 | ) | | (831 | ) |
| Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash | 6 |
| | (497 | ) | | 182 |
| |
| (Decrease) Increase in Cash, Cash Equivalents, and Restricted Cash | | (235 | ) | | 6 |
| | (497 | ) |
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 713 |
| | 1,210 |
| | 1,028 |
| 719 |
| | 713 |
| | 1,210 |
|
| Cash, Cash Equivalents, and Restricted Cash at End of Period | $ | 719 |
| | $ | 713 |
| | $ | 1,210 |
| $ | 484 |
| | $ | 719 |
| | $ | 713 |
|
Noble Energy, Inc.
Consolidated Statements of Shareholders' Equity
(millions)
| | | | 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, 2015 | $ | 5 |
| | $ | 6,360 |
| | $ | (33 | ) | | $ | (688 | ) | | $ | 4,726 |
| | $ | — |
| | $ | 10,370 |
| |
| Net (Loss) Income | — |
| | — |
| | — |
| | — |
| | (998 | ) | | 13 |
| | (985 | ) | |
| Stock-based Compensation | — |
| | 68 |
| | — |
| | — |
| | — |
| | — |
| | 68 |
| |
| Exercise of Stock Options | — |
| | 24 |
| | — |
| | — |
| | — |
| | — |
| | 24 |
| |
| Dividends (40 cents per share) | — |
| | — |
| | — |
| | — |
| | (172 | ) | | — |
| | (172 | ) | |
| Issuance of Noble Midstream Partners Common Units, Net of Offering Costs | — |
| | — |
|
| — |
| | — |
| | — |
| | 299 |
|
| 299 |
| |
| Other | — |
| | (2 | ) | | 2 |
| | (4 | ) | | — |
| | — |
| | (4 | ) | |
| 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 | — |
| | — |
| | — |
| | — |
| | (1,118 | ) | | 68 |
| | (1,050 | ) | — |
| | — |
| | — |
| | — |
| | (1,118 | ) | | 68 |
| | (1,050 | ) |
| Clayton Williams Energy Acquisition | — |
| | 1,876 |
| | — |
| | (25 | ) | | — |
| | — |
| | 1,851 |
| — |
| | 1,876 |
| | — |
| | (25 | ) | | — |
| | — |
| | 1,851 |
|
| Stock-based Compensation | — |
| | 100 |
| | — |
| | — |
| | — |
| | — |
| | 100 |
| — |
| | 100 |
| | — |
| | — |
| | — |
| | — |
| | 100 |
|
| Exercise of Stock Options | — |
| | 10 |
| | — |
| | — |
| | — |
| | — |
| | 10 |
| — |
| | 10 |
| | — |
| | — |
| | — |
| | — |
| | 10 |
|
| Dividends (40 cents per share) | — |
| | — |
| | — |
| | — |
| | (190 | ) | | — |
| | (190 | ) | — |
| | — |
| | — |
| | — |
| | (190 | ) | | — |
| | (190 | ) |
| Issuance of Noble Midstream Partners Common Units, Net of Offering Costs | — |
| | — |
| | — |
| | — |
| | — |
| | 312 |
| | 312 |
| — |
| | — |
| | — |
| | — |
| | — |
| | 312 |
| | 312 |
|
| Distributions to Noncontrolling Interest Owners | — |
| | — |
| | — |
| | — |
| | — |
| | (28 | ) | | (28 | ) | — |
| | — |
| | — |
| | — |
| | — |
| | (28 | ) | | (28 | ) |
| Other | — |
| | 2 |
| | 1 |
| | (8 | ) | | — |
| | 19 |
| | 14 |
| — |
| | 2 |
| | 1 |
| | (8 | ) | | — |
| | 19 |
| | 14 |
|
| December 31, 2017 | $ | 5 |
| | $ | 8,438 |
| | $ | (30 | ) | | $ | (725 | ) | | $ | 2,248 |
| | $ | 683 |
| | $ | 10,619 |
| $ | 5 |
| | $ | 8,438 |
| | $ | (30 | ) | | $ | (725 | ) | | $ | 2,248 |
| | $ | 683 |
| | $ | 10,619 |
|
| Net (Loss) Income | — |
| | — |
| | — |
| | — |
| | (66 | ) | | 80 |
| | 14 |
| — |
| | — |
| | — |
| | — |
| | (66 | ) | | 80 |
| | 14 |
|
| Stock-based Compensation | — |
| | 78 |
| | — |
| | — |
| | — |
| | — |
| | 78 |
| — |
| | 78 |
| | — |
| | — |
| | — |
| | — |
| | 78 |
|
| Dividends (43 cents per share) | — |
| | — |
| | — |
| | — |
| | (208 | ) | | — |
| | (208 | ) | — |
| | — |
| | — |
| | — |
| | (208 | ) | | — |
| | (208 | ) |
| Purchase and Retirement of Common Stock | — |
| | (295 | ) | | — |
| | — |
| | — |
| | — |
| | (295 | ) | — |
| | (295 | ) | | — |
| | — |
| | — |
| | — |
| | (295 | ) |
| Clayton Williams Energy Acquisition | — |
| | (25 | ) | | — |
| | — |
| | — |
| | — |
| | (25 | ) | — |
| | (25 | ) | | — |
| | — |
| | — |
| | — |
| | (25 | ) |
| Distributions to Noncontrolling Interest Owners | — |
| | — |
| | — |
| | — |
| | — |
| | (51 | ) | | (51 | ) | — |
| | — |
| | — |
| | — |
| | — |
| | (51 | ) | | (51 | ) |
| Contributions from Noncontrolling Interest Owners | — |
| | — |
| | — |
| | — |
| | — |
| | 353 |
| | 353 |
| — |
| | — |
| | — |
| | — |
| | — |
| | 353 |
| | 353 |
|
| Other | — |
| | 7 |
| | (2 | ) | | (5 | ) | | 6 |
| | (7 | ) | | (1 | ) | — |
| | 7 |
| | (2 | ) | | (5 | ) | | 6 |
| | (7 | ) | | (1 | ) |
| December 31, 2018 | $ | 5 |
| | $ | 8,203 |
| | $ | (32 | ) | | $ | (730 | ) | | $ | 1,980 |
| | $ | 1,058 |
| | $ | 10,484 |
| $ | 5 |
|
| $ | 8,203 |
|
| $ | (32 | ) |
| $ | (730 | ) |
| $ | 1,980 |
| | $ | 1,058 |
|
| $ | 10,484 |
|
| Net (Loss) Income | | — |
| | — |
| | — |
| | — |
| | (1,512 | ) | | 79 |
| | (1,433 | ) |
| Stock-based Compensation | | — |
| | 76 |
| | — |
| | — |
| | — |
| | — |
| | 76 |
|
| Dividends (47 cents per share) | | — |
| | — |
| | — |
| | — |
| | (227 | ) | | — |
| | (227 | ) |
| Issuance of Noble Midstream Partners Common Units, Net of Offering Costs | | — |
| | 110 |
| | — |
| | — |
| | — |
| | 100 |
| | 210 |
|
| Subsidiary Equity Transaction | | — |
| | 538 |
| | — |
| | — |
| | — |
| | (538 | ) | | — |
|
| Distributions to Noncontrolling Interest Owners | | — |
| | — |
| | — |
| | — |
| | — |
| | (74 | ) | | (74 | ) |
| Contributions from Noncontrolling Interest Owners | | — |
| | — |
| | — |
| | — |
| | — |
| | 37 |
| | 37 |
|
| Other | | — |
| | — |
| | 1 |
| | (2 | ) | | — |
| | (17 | ) | | (18 | ) |
| December 31, 2019 | | $ | 5 |
| | $ | 8,927 |
| | $ | (31 | ) | | $ | (732 | ) | | $ | 241 |
| | $ | 645 |
| | $ | 9,055 |
|
The accompanying notes are an integral part of these financial statements.
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Nature of OperationsNoble Energy, Inc. (Noble Energy, we or us) is a leading independent energy company engaged in worldwide crude oil and natural gas exploration and production. Our historical operating areas include: US onshore, primarily the DJ Basin, Delaware Basin, Eagle Ford Shale and Marcellus Shale (until June 2017); US offshore Gulf of Mexico (until April 2018); Eastern Mediterranean; and West Africa. Our Midstream segment develops, owns, operates and acquires domestic midstream infrastructure assets, or invests in other midstream entities, with current focus areas being the DJ and Delaware Basins.
Note 1. Summary of Significant Accounting Policies
General Noble Energy, Inc. (Noble Energy, we or us) is a leading independent energy company engaged in worldwide crude oil and natural gas exploration and production. Our historical operating areas include: US onshore, primarily the DJ Basin, Delaware Basin, Eagle Ford Shale and Marcellus Shale (until June 2017); US offshore Gulf of Mexico (until April 2018); Eastern Mediterranean; and West Africa. Our Midstream segment develops, owns, operates and acquires domestic midstream infrastructure assets, or invests in other midstream entities, with current focus areas being the DJ and Delaware Basins.
Basis of Presentation and Consolidation We use accounting policies that conform to US GAAP. Significant policies are discussed below. Our consolidated accounts include our accounts and the accounts of our wholly-owned subsidiaries. All significant intercompanyIntercompany balances and transactions have been eliminated upon consolidation. For the periods presented, net income or loss is materially consistent with comprehensive income or loss. Certain prior-period amounts have been reclassified to conform to the current period presentation.
Segment Information Accounting policies are consistent across geographical segments. Transfers between segments are accounted for at market value. We do not consider interest income or expense and income tax benefit or expense in our evaluation of the performance of geographical segments. See Note 3. Segment Information. Consolidated Variable Interest Entity (VIE)Noble Midstream Partners Noble Energy has determined that the partners with equity at risk in Noble Midstream Partners LP (Noble Midstream Partners)Partners, Nasdaq: NBLX) lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact Noble Midstream Partners' economic performance; therefore, Noble Midstream Partners is considered a VIE.variable interest entity (VIE). Through Noble Energy's ownership interest in Noble Midstream GP LLC (the General Partner to Noble Midstream Partners), Noble Energy has the authority to direct the activities that most significantly affect economic performance and the obligation to absorb losses or the right to receive benefits that could be potentially significant to Noble Midstream Partners. Therefore, Noble Energy is considered the primary beneficiary and consolidates Noble Midstream Partners.
Noncontrolling InterestsIn third quarter 2016, Noble Midstream Partners, a subsidiary of Noble Energy, completed its initial public offering of common units. As a result, we present ourOur consolidated financial statements withinclude both noncontrolling interests and a redeemable noncontrolling interest section representinginterest. The noncontrolling interests represent the public's ownership in Noble Midstream Partners. We also presentPartners and third-party ownership in Noble Midstream Partners' consolidated non-wholly owned subsidiariessubsidiaries.
The redeemable noncontrolling interest represents third-party preferred equity secured by Noble Midstream Partners in March 2019. The entire equity commitment totals $200 million, of which $100 million was funded and the remaining $100 million is available for a one year period, subject to certain conditions precedent. The preferred equity is perpetual and has a 6.5% annual dividend rate. Noble Midstream Partners can redeem the preferred equity in whole or in part at any time for cash at a predetermined redemption price. The preferred equity partner can request redemption at a pre-determined base return following the later of the sixth anniversary of the preferred equity closing or the fifth anniversary of the completion date of the EPIC Crude Oil Pipeline (defined below). As the preferred equity partner’s redemption right is outside of Noble Midstream Partners’ control, the preferred equity is not considered to be a component of shareholders' equity and, therefore, is reported as mezzanine equity. In addition, because the preferred equity is held by a third-party, it is considered a redeemable noncontrolling interests.interest. We accrete changes in the preferred equity redemption value from the issuance date to the earliest redemption date and offset the accretion against additional paid in capital. See Note 5.4. Acquisitions and Divestitures. Equity Method of Accounting We use the equity method of accounting for investments in entities that we do not control but over which we exert significant influence. OurFor certain entities, we serve as the operator and exert significant influence over the day-to-day operations. For other entities, we do not serve as the operator; however, our voting position on management committees or the board of directors allows us to exert significant influence over decisions regarding capital investments, budgets, turnarounds, maintenance, monetization decisions and other project matters. We consider these equity investees own and operate various midstream assets which we consider anmethod investments essential componentcomponents of our business and aas well as necessary and integral element toelements of our value chain involving the monetizationin support of natural gas. With our partners, we engage in joint strategic operational and financial decision making for these entities.
ongoing upstream operations. In order to reflect the economics associated with our integrated upstream value chain, described above, we include income from equity method investeesinvestments as a component of revenues in our consolidated statements of operations.
We carry equity method investments at our share of net assets of the equity investees plus loans and advances, and include the investments in other noncurrent assets on our consolidated balance sheets. Within our consolidated statements of cash flows, activity is reflected within cash flows provided by operating activities and cash flows used in investing activities. Differences in the basis of the investment and the separate net asset value of the investee, if any, are amortized into income over the remaining useful life of the underlying assets. Our share of income taxes incurred directly by the equity method investees is reported in income from equity method investees and is not included in our income tax provision in our consolidated statements of operations. See Note 15.5. Equity Method Investments. Foreign CurrencyThe 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.
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, NGL and natural gas reserves are the most significant of our estimates. AllSee Supplemental Oil and Gas Information (Unaudited). Other items subject to estimates and assumptions include the carrying amounts of the reserves data included in this Annual Report Form 10-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, NGLsinventory, property, plant and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil, NGLequipment, equity method investments, goodwill, intangible assets, exit cost liabilities and natural gas reserves. The accuracy of any reserves estimate is a function of the qualityAROs, valuation
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
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, NGLs 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 Senior Vice President – Corporate Development and certain members of senior management. See Supplemental Oil and Gas Information (Unaudited).Other items subject to estimates and assumptions include the carrying amounts of inventory, property, plant and equipment, goodwill, exit costs and AROs, valuation allowances for receivables and deferred income tax assets, and valuation of derivative instruments, and fair values, among others. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. Declines in commodity prices, or other events, could result in a reduction in our fair value estimates and cause us to perform analyses to determine if our oil and gas properties, or other long-lived assets, are impaired. As future commodity prices cannot be determined accurately, actual results could differ significantly from our estimates.
Reclassifications The revenues and expenses associated with mitigating Marcellus Shale retained firm transportation contracts, including costs associated with exiting certain of those contracts, were reclassified from our oil and gas exploration and production segment to Corporate as these items are not representative of retained upstream operations.Fair Value Measurements See Note 3. Segment Information.Certain other prior-period amounts have been reclassified to conform to the current period presentation.
Fair Value Measurements assets and liabilities are measured at fair value on a recurring basis on our consolidated balance sheets. Other assets and liabilities are measured at fair value on a nonrecurring basis. 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 14. Fair Value MeasurementsThe carrying amounts of cash and Disclosures.cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term nature or maturity of the instruments. 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.
Accounts Receivable and Allowance for Doubtful AccountsExpected Credit Losses Our accounts receivable result primarily from sales of crude oil, NGL and natural gas production and joint interest billings to our partners for their share of expenses on joint venture projects for which we are the operator. The majority of these receivables have payment terms of 30 days or less. Our accounts receivable reflect areflects broad national and international customer base, which limits our exposure to concentrations of credit risk. We continually monitor the creditworthiness of the counterparties and we have obtained credit enhancements from some parties in the form of parental guarantees or letters of credit.
We routinelyAt the end of each reporting period, we assess the recoverability of all material receivables using historical data, current market conditions, and reasonable and supportable forecasts of future economic conditions to determine their expected collectibility. We accrue a reserve on a receivableThe loss given default method is used when, based on management’smanagement's judgment, it is probable thatan allowance for expected credit losses should be accrued on a material receivable will notto reflect the net amount expected to be collected and the amountcollected. See “Recently Adopted Accounting Standards” below for discussion on our early adoption of such reserve may be reasonably estimated. See Note 2. Additional Financial Statement Information.InventoriesAccounting Standards Update No. 2016-13 (ASU 2016-13): Financial Instruments – Credit Losses. Inventories consist primarily of tubular goods and production equipment used in our oil and gas operations and crude oil produced but not yet sold. Materials and supplies inventories are stated at the lower of cost or net realizable value. The assets will be reduced to their fair value if the carrying amount exceeds net realizable value. The cost of crude oil inventory includes production costs and depreciation, depletion and amortization (DD&A) of oil and gas properties. See Note 2. Additional Financial Statement Information.Property, Plant and Equipment Significant accounting policies for our property, plant and equipment are as follows:
Oil and Gas Properties (Successful Efforts Method of Accounting) 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 bydepleted using the unit-of-production method based on proved crude oil, NGL and natural gas reserves on a field-by-field basis, as estimated by our qualified petroleum engineers. Costs of certain gathering facilities or processing plants serving a number of properties or used for third-party processing are depreciated using the straight-line method over the useful lives of the assets ranging from three to thirty years. Upon sale or retirement of depreciable or depletable property, the cost and related
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
accumulated DD&A areis eliminated fromand we either adjust the accounts andbasis of the resultingrespective asset or recognize a gain or loss is recognized.loss. Costs related to repair and maintenance activities are expensed as incurred.
Proved Property Impairment For our proved properties, we routinely assess whether impairment indicators arise during any given quarterexist and have processes in place to ensure that we become aware of such indicators. Impairment indicators include, but are not limited to, sustained decreases in commodity prices, negative revisions of proved reserves, and increases in development or operating costs. In the event that impairment indicators exist, weWe conduct an impairment test.test in the event impairment indicators exist. Under such test, we estimate future net cash flows expected in connection with the property and compare such future net cash flows to the carrying amount of the property to determine if the carrying amount is recoverable. Other long-lived assets, such as our midstream assets, are evaluated in a manner consistent with our policy for proved property.
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
When the carrying amount of athe proved property exceeds its estimated undiscounted future net cash flows, an impairment is indicated and the carrying amountfair value of the asset is reduced to estimated fair value.then estimated. Fair value inputs, which are level 3 on the fair value hierarchy, 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 net cash flows are based on management’s expectations for the future and include estimates of future crude oil and natural gas production, commodity prices based on published forward commodity price curves or contract prices as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate.
We recorded In the event of an impairment, charges in 2018, 2017 and 2016 and itthe carrying amount of the proved property is possible that other assets could become impaired in the future.reduced to estimated fair value. See Note 14. Fair Value Measurements and Disclosures10. Impairments.Unproved Property Impairment Our unproved properties consist of leasehold costs and allocated value to probable and possible reserves resulting from acquisitions. Undeveloped leasehold costs are derived from allocated fair values as a result of business combinations or other purchases of unproved properties and are subject to impairment testing. We reclassify undeveloped leasehold costs to proved property costs when, as a result of exploration and development activities, probable and possible resources are reclassified to proved reserves, including proved undeveloped reserves.
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.impairment. 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 net 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, NGL and natural gas reserves, future commodity prices and future costs to produce the reserves. Cash flow estimates relatedReserves volumes are reduced by risk adjustments applied to probable and possible reserves are reduced by additional risk-weighting factors.
It is possible that unproved oil and gas properties, including undeveloped leases, could become impaired in the future if commodity prices decline or if there are changes in exploration plans or the timing and extent of development activities.reserves. See Note 7.6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.Properties Acquired in Business Combinations When sufficient market data is not available, we determine the fair values of proved and unproved oil and gas properties acquired in transactions accounted for as business combinations by preparing estimates of cash flows from the production of crude oil, NGL 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. When estimating and valuing unproved reserves, discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors.
For other assets acquired in business combinations, we use a combination of available cost and market data and/or estimated cash flows to determine the fair values.
Assets Held for Sale We occasionally market oil and gas properties for sale. At the end of each reporting period, we evaluate properties being marketed for sale to determine whether any should be reclassified as held for sale. TheIf 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 isare met, the property is reclassified as held for sale on our consolidated balance sheets and will be valued at the lower of net book value or anticipated sales proceeds less costs to sell. Impairment expense would beis recorded for any excess of net book value over anticipated sales proceeds less costs to sell.
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 international projects, it may take us more than one year to evaluate the future potential of the exploratory well
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| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
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, permits and approvals and we believe they will be obtained. We assess the status of suspended exploratory well costs on a quarterly basis. See Note 7.6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs. Property, Plant and Equipment, Other Other property includes automobiles, trucks, airplanes,an airplane, office furniture, computer equipment, buildings, leasehold improvements and other fixed assets. These items are recorded at cost and are depreciated using the straight-line method based on expected lives of the individual assets or group of assets, ranging from three to thirty years. Other property also includes linefill, which is recorded at cost to produce into the production line. Linefill is not subject to depreciation but is reviewed for impairment.
Capitalization of Interest We capitalize interest costs associated with the development and construction of significant properties or projects to bring them to a condition and location necessary for their intended use, which for crude oil and natural gas assets is at first production from the field. Interest is capitalized using an interest rate equivalent to the weighted average interest rate we pay on long-term debt, including our unsecured revolving credit facilities, term loan credit facilities and bonds.Senior
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Notes. Capitalized interest is included in the cost of oil and gas assets and is amortized with other costs on a unit-of-production basis. Capitalized interest totaled $73 million in 2018, $49 million in 2017, and $84 million in 2016.
Asset Retirement Obligations Asset Retirement Obligationsretirement obligations (AROs) consist of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. We recognize the fair value of a liability for an ARO in the period in which we have an existing legal obligation associated with the retirement that can reasonably be estimated. The associated asset retirement cost is capitalized as part of the carrying value of the oil and gas asset. The asset retirement cost is recorded at estimated fair value, measured by the expected future cash outflows required to satisfy the obligation discounted at our credit-adjusted risk-free rate. After initial recording, the liability is increased for the passage of time, with the increase being reflected as accretion expense included in DD&A expense in the consolidated statements of operations. Subsequent adjustments in the cost estimate are reflected in the liability and the amounts continue to be amortized over the useful life of the related long-lived asset. See Note 8.7. Asset Retirement Obligations. GoodwillGoodwill is not amortized to earnings but is assessed for impairment at the reporting unit level on an annual basis, or more frequently as circumstances require. We use qualitative and quantitative assessments to determine whether goodwill is impaired. If we conclude that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, an impairment charge is recognized for the amount by which the carrying amount exceeds the fair value.
We conducted our annual goodwill impairment assessment as of September 30, 2018. As of that date, our consolidated balance sheet included goodwill of $1.4 billion, of which $1.3 billion was allocated to our Texas reporting unit, included within our oil and gas exploration and production segment, and $110 million was allocated to our Midstream reporting unit. At that time, we concluded that goodwill was not impaired. During fourth quarter 2018, we considered changes to facts and circumstances, particularly the decline in WTI strip pricing, increase in operating and capital costs, as well as our development plan, and concluded that the goodwill allocated to the Texas reporting unit was fully impaired and recorded a charge of $1.3 billion. See Note 6. Goodwill Impairment.Intangible Assets Intangible assets consist of customer contracts and relationships acquired by Noble Midstream Partners through Black Diamond in its acquisition of Saddle Butte Rockies Midstream, LLC and affiliates (collectively, Saddle Butte). Wethat were recorded the intangible assets at their estimated fair values at the date of acquisition. Amortization is calculated using the straight-line method, which reflects the pattern in which the estimated economic benefit is expected to be received over the estimated useful life of the intangible assets, which is currently over periods of seven to 13 years. As of December 31, 2018,2019, the net book value of our intangible assets was $310 million. Amortization expense, which is equivalent to$278 million, net of accumulated amortization for 2018, of $30 million is included in DD&A expense in our consolidated statements of operations and statements of cash flows.$62 million. Intangible assets with finite useful lives are reviewed for impairment when events or changes in circumstances indicate that the carrying amountamounts of such assets may not be recoverable. See Note 5.4. Acquisitions and Divestitures. Exit Costs In accordance with Accounting Standards Codification (ASC) 420 – Exit or Disposal Cost Obligations, weWe recognize the fair value of a liability for an exit cost in the period in which a liability is incurred. The recognition and fair value estimation of an exit cost liability requires that management take into account certain estimates and assumptions including: the determination of whether a cease-use date has occurred (defined as the date the entity ceases using the right conveyed by the contract, for example, the right to use a leased property or to receive future goods or services); the amount, if any, of economic benefit that is expected to be obtained from a contract through partial use or release; and our estimate of costs that will continue to be incurred under the contract. We record exit cost liabilities at estimated fairassumptions. Fair value estimates are based on expected future discounted cash outflows required to satisfy the obligation, net of estimated recoveries, and discounted.recoveries. In periods subsequent to initial measurement,
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
changes to an exit cost liability, including changes resulting from revisions to either the timing or the amount of estimated cash flows over the future contract period, will beare recognized as an adjustment to the liability in the period of the change.
Exit cost liabilities are included in other current and other noncurrent liabilities on our consolidated balance sheets. Exit costs, and associated accretion expense, are included in other operating expense, net in our consolidated statements of operations.
Accrued exit costs at December 31, 2018 and 2017 relate primarily to estimated costs associated with Marcellus Shale contracts. See Note 10. Marcellus Shale Firm11. Exit Cost – Transportation Commitments.Derivative Instruments and Hedging Activities All derivative instruments (including certain derivative instruments embedded in other contracts) are recorded on our consolidated balance sheets as either an asset or liability and are measured at fair value. We account for our commodity derivative instruments using mark-to-market accounting and recognize all gains and losses in earnings during the period in which they occur. Our consolidated statements of cash flows include the non-cash portion of gain and loss on commodity derivative instruments, which represents the difference between the total gain and loss on commodity derivative instruments and the cash received or paid on settlements of commodity derivative instruments during the period.
We offset the fair value amounts recognized for derivative instruments against the fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral. The cash collateral (commonly referred to as a “margin”) must arise from derivative instruments recognized at fair value that are executed with the same counterparty under a master agreement with netting clauses. See Note 13.14. Derivative Instruments and Hedging Activities. Stock-Based Compensation Restricted stock and stock options issued to employees and directors are recorded on grant-date at fair value. Expense is recognized on a straight-line basis over the employee’s and director’s requisite service period (generally the vesting period of the award) in the consolidated statements of operations. In 2016, we issued cash-settled awards to certain employees in lieu of a portion of restricted stock and stock options. We recognize the value of cash-settled awards utilizing the liability method as defined under ASC Topic 718, Compensation – Stock Compensation. The fair value of liability awards is remeasured at each reporting date, based on the fair market value of a share of common stock of the Company as of the reporting date, through the settlement date with the change in fair value recognized as compensation expense over that period. See Note 17.16. Stock-Based and Other Compensation Plans. Other Postretirement Benefit Plans We recognize the funded status (the difference between the fair value of plan assets and the projected benefit obligation) of restoration and other postretirement benefit plans in the consolidated balance sheets, with a corresponding adjustment to accumulated other comprehensive loss (AOCL), net of tax. The amount remaining in AOCL at December 31, 2018 represents unrecognized net actuarial loss and unrecognized prior service cost related to our restoration plan. These amounts are currently being recognized as net periodic benefit cost pursuant to our historical accounting 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.
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 11.12. Commitments and Contingencies. We self-insure the medical and dental coverage provided to certain employees, and the deductibles for workers’ compensation, automobile liability and general liability coverage. Liabilities are accrued for self-insured claims, or when estimated losses exceed coverage limits, and when sufficient information is available to reasonably estimate the amount of the loss.
Income Taxes and Impact of Tax Reform Legislation 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.
We account for income taxes using 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.
In assessing the realizability of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income in the appropriate tax jurisdictions during the periods in which those temporary differences become deductible. We consider the scheduled reversal of deferred tax liabilities, current financial position, results of operations, projected future taxable income and tax planning strategies as well as current and forecasted business economics in the oil and gas industry. The
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
On December 22, 2017,amount of the US Congress enacteddeferred tax assets considered realizable could be reduced in the Tax Cuts and Jobs Act (Tax Reform Legislation), which made significant changes to US federalfuture if estimates of future taxable income tax law affecting us.during the carryforward period are reduced. See Note 12.13. 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 RecognitionOur revenues are derived primarily from the sale of crude oil, NGL and natural gas production to crude oil refining companies, midstream marketing companies, marketers, industrial companies, electric utility companies, independent power producers and cogeneration facilities, among others. We recognize revenues based on the amount of product sold to a customer when control transfers to the customer. Our revenue arrangements include the following:
Crude Oil Sale Arrangements – US We sell our share of crude oil production under both short-term and long-term contracts at market-based prices, adjusted for location, quality and transportation charges. Revenue is measured based on the index-based contract price, and may include adjustments for market differentials and downstream costs incurred by the customer, including gathering, transportation, and fuel costs.
Crude Oil Sale Arrangements – West Africa We sell our share of crude oil and condensate at market-based prices and recognize revenue at the time a crude oil cargo is loaded onto the tanker.
Natural Gas and NGLs Sale Arrangements – US We evaluate these arrangements to determine whether the processor is a service provider or a customer. In arrangements where we determine that the processor is a customer, we record revenue when the processor takes control of the natural gas and NGLs and in the amount of proceeds expected to be received, net of any fees or deductions charged by the processor. In other arrangements, we receive natural gas and NGL products “in-kind” after processing at the tailgate of the plant. In these arrangements, where we determine that the processor is a service provider, we record revenue and applicable gathering, processing, transportation and fractionation fees on a gross basis at the time the product is delivered to the end customer.
Natural Gas Sale Arrangements – West AfricaWe sell our share of natural gas production under a long-term contract for $0.25 per MMBtu to a methanol plant, a liquefied petroleum gas (LPG) plant, a liquefied natural gas (LNG) plant and a power generation plant. We recognize revenue upon transfer of control of product to these processors.
Natural Gas Sale Arrangements – Eastern Mediterranean We sell our share of natural gas production primarily based on long-term contracts with fixed volume commitments. Performance obligations are satisfied over time using production output to measure progress. The nature of these contracts gives rise to several types of variable consideration, including index-based annual price escalations, commodity-based index pricing, tiered pricing and sales price discounts in periods of volume deficiencies. Additionally, the majority of these sales contracts contain take-or-pay provisions whereby the customers are required to purchase a contractual minimum over varying time periods. We record revenues related to the volumes delivered at an amount that reflects the contract price at the time of delivery.
The following table provides estimated future revenues for remaining performance obligations under fixed volume natural gas sales agreements using the contractual fixed base or floor price provision in effect. Actual future sales volumes under these agreements may exceed future minimum volume commitments. In addition, future sales revenues will vary due to components of variable consideration toabove the contractual base or floor provision, such as index-based escalations and market price changes. Certain of these contracts contain embedded derivatives for which we expecthave elected the normal purchases and normal sales scope exception, which excludes the derivatives from mark-to-market accounting.
Estimated future revenues related to be entitledremaining performance obligations were as follows as of December 31, 2019: |
| | | | | | | | | | | | | | | | | | | | | |
| (millions) | 2020 | 2021 | 2022 | 2023 | 2024 | Thereafter | Total |
Natural Gas Revenues(1) | $ | 743 |
| $ | 768 |
| $ | 583 |
| $ | 583 |
| $ | 583 |
| $ | 5,259 |
| $ | 8,519 |
|
| |
(1) | Includes amounts related to the Tamar and Leviathan fields, offshore Israel. |
Oil and Gas Purchase and Sale Arrangements We enter into separate third-party purchase and sale transactions at prevailing market prices to mitigate unutilized pipeline transportation commitments. We recognize associated revenues and expenses on a gross basis, as we act as a principal in exchangethese transactions by assuming control of the purchased commodity before it is transferred to the customer. We also enter into crude oil buy/sell arrangements that effect a change in location and/or grade with required repurchase of crude oil at a delivery point. We account for transferring goods orthese transactions on a net basis and record the residual transportation fee within gathering, transportation and processing expense in the consolidated statements of operations.
Midstream Services Arrangements Third-party Midstream services revenues relate to a customer,fixed fee arrangements for gathering, transportation and storage services. Our performance obligations for the provision of such services are satisfied over time using a five-step process, in accordance with ASC 606 – volumes delivered as the measure of progress.Revenue from Contracts with Customers. See Note 4. Revenue from Contracts with Customers.
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Basic and Diluted Earnings (Loss) Per Share Attributable to Noble Energy Basic earnings (loss) per share (EPS) of our common stock is computed on the basis of the weighted average number of shares outstanding during each period. The diluted EPS of our common stock includes the effect of outstanding common stock equivalents such as stock options, shares of restricted stock, and/or shares of our stock held in a rabbi trust, except in periods in which there is a net loss. In the event of a net loss, we exclude the effect of outstanding common stock equivalents from the calculation of diluted EPS as the inclusion would be anti-dilutive.
Recently IssuedAdopted Accounting Standards
Leases In February 2016, the Financial Accounting Standards Board (FASB) issuedEffective January 1, 2019, we adopted Accounting Standards Update No. 2016-02 (ASU 2016-02):, which created Leases.Topic 842 – Leases (ASC 842). The standard requires lessees to recognize a right of useright-of-use (ROU) asset (ROU asset) and lease liability on the balance sheet for the rights and obligations created by leases. ASU 2016-02 also requires disclosures designedThis standard does not apply to give financial statement users information onleases to explore for or use minerals, oil, natural gas or similar nonregenerative resources, including the amount, timing,intangible right to explore for those resources and uncertainty of cash flows arising from leases. In July 2018,rights to use the FASB issued Accounting Standards Update No. 2018-11 (ASU 2018-11): Leases (Topic 842): Targeted Improvements,land in which provides for an alternative transition method by allowing entities to initially applythose natural resources are contained.
Upon adoption, we elected the new leases standard at the adoption date (January 1, 2019) and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption (comparative periods presented in the financial statements will continue to be in accordance with current GAAP (Topic 840, Leases)). The standard is 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, field services and well equipment, office space and other assets. We adopted the new standard on the effective date of January 1, 2019, using a modified retrospective approach as permitted under ASU 2018-11.
The new standard provides a number offollowing optional practical expedients in transition. We expect to:expedients:
elect the package of 'practical expedients', which permitstransition “practical expedients,” permitting us not to reassess under the new standard our prior conclusions about lease identification, lease classification and initial direct costs;
elect the practical expedient pertaining to land easements, and planallowing us to account for existing land easements under our currentprevious accounting policy;
elect the short-term lease recognition exemption for all leases that qualify and, as such, no ROU asset or lease liability will be recorded on the balance sheet and no transition adjustment will be required for short-term leases; and
elect the practical expedient to not separate lease and non-lease components for allthe majority of our leases.leases (elected by asset class).
We do not expect to electadopted ASC 842 using the hindsight practical expedient in determining the lease termmodified retrospective method and assessing impairment of ROU assets when transitioning to ASC 842.
We continue to execute a project plan, which includes contract review and assessment, data collection, and evaluation of our systems, processes and internal controls. In addition, we have implemented a new lease accounting software which will facilitate the adoption of this standard.
While we are finalizing our assessment of the effect of adoption, we do not expect the adoption and implementation of this standard will have a material effect on our financial statements. We estimate the most significant impact will relate to the recognition of newrecorded ROU assets and lease liabilities on our balance sheet forof $282 million and $287 million, respectively, primarily related to operating leases, as well as additional disclosures. Consequently, with adoption, we expect to recognize additional operating liabilities ranging between $200 million to $350 million with correspondingleases. ROU assets of the same amountand corresponding liabilities are based on the present value of the remaining minimum lease payments. Our accounting for finance leases remains substantially unchanged. Adoption of ASC 842 did not materially impact our consolidated statement of operations and comprehensive income and had no impact on our consolidated statement of cash flows.
Additional information related to our accounting policies for leases is as follows:
Most of our leases do not provide implicit borrowing rates; therefore, using the portfolio approach, we determine the present value of lease payments using hypothetical secured borrowing rates based on information available at lease commencement.
Leases with an initial term of 12 months or less are not recorded on the balance sheet and we recognize lease expense for these leases on a straight-line basis over the lease term. Most leases include one or more options to renew, with renewal terms that can extend the lease term from one month to one year or more. Additionally, some of our leases include an option for early termination. We include renewal periods and exclude termination periods from our lease term if, at commencement, it is reasonably likely that we will exercise the option.
Certain of our lease agreements include rental payments under current leasing standardsthat are adjusted periodically for existing operating leases.inflation or passage of time. These step payments are included within our present value calculation as they are known adjustments at commencement. Variable payments related to lease agreements are not material.
We have lease agreements that include lease and non-lease components, such as equipment maintenance, that are generally accounted for as a single lease component. For these leases, lease payments include all fixed payments stated within the contract. For other leases, such as office space, lease and non-lease components are accounted for separately. While some lease agreements include residual value guarantees, there are no material guarantees that impact our lease payments.
ROU assets are reviewed for impairment when events or changes in circumstances indicate that the carrying amounts of such assets may not be recoverable.
Financial Instruments: Credit Losses In June 2016, the FASB issued Accounting Standards Update No.ASU 2016-13, (ASU 2016-13): Financial Instruments – Credit Losses, which replaces the incurred loss impairment methodology with a methodology that reflectsan expected credit losses. The update is intended to provideloss methodology for financial statement users with more useful information about expectedinstruments, including financial assets measured at amortized cost, such as trade and joint interest billing receivables, and off-balance sheet credit losses.exposures not accounted for as insurance, such as financial guarantees and other unfunded loan commitments. The amended standard is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. From evaluation ofWe early adopted this ASU in fourth quarter 2019. This adoption did not have a material impact on our current credit portfolio, financial statements.
Income TaxesIn December 2019, the FASB released Accounting Standards Update No. 2019-12 (ASU 2019-12): IncomeTaxes (Topic 740) – Simplifying the Accounting for Income Taxes, which includes receivablesremoves certain exceptions for commodity sales,recognizing deferred taxes for investments, performing intraperiod allocation and calculating income taxes in interim periods. The ASU also adds
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
joint interest billings due from partnersguidance to reduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and other receivables, historical credit losses have been de minimis and we believe that our expected future credit losses would not be significant. As such, we do not believe adoptionallocating taxes to members of the standard will have a material impact on our financial statements.
Derivatives and Hedging – Targeted Improvements to Accounting for Hedging Activities In August 2017, the FASB issued Accounting Standards Update No. 2017-12 (ASU 2017-12): Derivatives and Hedging – Targeted Improvements to Accounting for Hedging Activities. The update is intended to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition to that main objective, ASU 2017-12 makes certain targeted improvements to simplify the application of the hedge accounting guidance in current US GAAP.consolidated group. The amended standard is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We are currently evaluating the provisions of ASU 2017-12.
Intangibles – Goodwill and Other – Internal-Use SoftwareIn August 2018, the FASB issued Accounting Standards Update No. 2018-15 (ASU 2018-15): Intangibles – Goodwill and Other – Internal-Use Software to align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The amended standard is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. We are currently evaluating the provisions of ASU 2018-15.
Recently Adopted Accounting Standards
Topic 606, Revenue from Contracts with Customers In May 2014, the FASB issued Accounting Standards Update No. 2014-09 (ASU 2014-09), which creates Topic 606, Revenue from Contracts with Customers (ASC 606). We adopted ASC 606 on January 1, 2018, using the modified retrospective method. See Note 4. Revenue from Contracts with Customers.Statement of Cash Flows – Restricted Cash In November 2016, the FASB issued Accounting Standards Update No. 2016-18 (ASU 2016-18): Statement of Cash Flows – Restricted Cash. We adopted ASU 2016-18 in the first quarter of 2018, using the retrospective method. ASU 2016-18 requires that restricted cash and cash equivalents be included with cash and cash equivalents when reconciling the total beginning and ending amounts for the periods shown on the statement of cash flows. There are no other impacts on our results of operations, financial condition or cash flows.
Intangibles – Goodwill and Other: Simplifying the Test for Goodwill Impairment In January 2017, the FASB issued Accounting Standards Update No. 2017-04 (ASU 2017-04): Intangibles – Goodwill and Other – Simplifying the Test for Goodwill Impairment to simplify how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. Under the new standard, we will perform our goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount, with an impairment charge being recognized for the amount by which the carrying amount exceeds the reporting unit’s fair value. ASU 2017-04 will be effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019,2020, with early adoption permitted. We early adopted this ASU in fourth quarter 2018.2019. This adoption did not have a material impact on our financial statements.
Recently Issued Accounting Standards
Accumulated Other Comprehensive Income In February 2018, the FASB issued Accounting Standards Update No. 2018-02 (ASU 2018-02): Income Statement – Reporting Comprehensive Income None that are expected to allow reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Reform Legislation. ASU 2018-02 is effective for annual and interim periods beginning after December 15, 2018, with early adoption permitted. We early adopted this ASU in fourth quarter 2018, reclassifying the tax effect of approximately $6 million stranded in accumulated other comprehensive income to retained earnings. This adoption did not have a material impact on our financial statements.
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Note 2. Additional Financial Statement Information
Statements of Operations Information Other statements of operations information is as follows: | | | | | Year Ended December 31, | Year Ended December 31, |
| (millions) | | 2018 | | 2017 | | 2016 | 2019 | | 2018 | | 2017 |
| Sales of Purchased Oil and Gas and Other | | |
| | |
| | |
| |
Sales of Purchased Oil and Gas (1) | | $ | 275 |
| | $ | — |
| | $ | — |
| |
| Income from Equity Method Investees | | 172 |
| | 177 |
| | 102 |
| |
| Other Revenue | | |
| | |
| | |
|
| Income from Equity Method Investments and Other | | $ | 51 |
| | $ | 172 |
| | $ | 177 |
|
| Midstream Services Revenues - Third Party | | 78 |
| | 19 |
| | — |
| 94 |
| | 78 |
| | 19 |
|
| Total | | $ | 525 |
| | $ | 196 |
| | $ | 102 |
| $ | 145 |
| | $ | 250 |
| | $ | 196 |
|
| Production Expense | | | | | | | | | | | |
| Lease Operating Expense | | $ | 576 |
| | $ | 571 |
| | $ | 542 |
| $ | 532 |
| | $ | 576 |
| | $ | 571 |
|
| Production and Ad Valorem Taxes | | 190 |
| | 118 |
| | 57 |
| 175 |
| | 190 |
| | 118 |
|
| Gathering, Transportation and Processing Expense | | 393 |
| | 432 |
| | 480 |
| 417 |
| | 393 |
| | 432 |
|
| Other Royalty Expense | | 38 |
| | 20 |
| | 21 |
| 13 |
| | 38 |
| | 20 |
|
| Total | | $ | 1,197 |
| | $ | 1,141 |
| | $ | 1,100 |
| $ | 1,137 |
| | $ | 1,197 |
| | $ | 1,141 |
|
| Exploration Expense | | | | | | | | | | | |
| Leasehold Impairment and Amortization | | $ | 1 |
| | $ | 62 |
| | $ | 148 |
| $ | — |
| | $ | 1 |
| | $ | 62 |
|
| Dry Hole Cost | | 1 |
| | 9 |
| | 579 |
| |
Dry Hole Cost (1) | | 100 |
| | 1 |
| | 9 |
|
| Seismic, Geological and Geophysical | | 22 |
| | 27 |
| | 76 |
| 21 |
| | 22 |
| | 27 |
|
| Staff Expense | | 54 |
| | 55 |
| | 77 |
| 48 |
| | 54 |
| | 55 |
|
| Other | | 51 |
| | 35 |
| | 45 |
| 33 |
| | 51 |
| | 35 |
|
| Total | | $ | 129 |
| | $ | 188 |
| | $ | 925 |
| $ | 202 |
| | $ | 129 |
| | $ | 188 |
|
| Loss on Marcellus Shale Upstream Divestiture and Other | | | | | | | | | | | |
| Loss on Sale | | $ | — |
| | $ | 2,270 |
| | $ | — |
| $ | — |
| | $ | — |
| | $ | 2,270 |
|
| Exit Cost | | — |
| | 93 |
| | — |
| — |
| | — |
| | 93 |
|
| Other | | — |
| | 16 |
| | — |
| — |
| | — |
| | 16 |
|
| Total | | $ | — |
| | $ | 2,379 |
| | $ | — |
| $ | — |
| | $ | — |
| | $ | 2,379 |
|
| Other Operating Expense, Net | | |
| | |
| | |
| |
| | |
| | |
|
Marketing Expense (2) | | $ | 40 |
| | $ | 47 |
| | $ | 58 |
| |
Cost of Purchased Oil and Gas (1) | | 296 |
| | — |
| | — |
| |
| Marketing Expense | | $ | 34 |
| | $ | 40 |
| | $ | 47 |
|
Firm Transportation Exit Cost (2) | | 88 |
| | — |
| | — |
|
| Clayton Williams Energy Acquisition Expenses | | — |
| | 100 |
| | — |
| — |
| | — |
| | 100 |
|
Gain on Asset Retirement Obligation Revisions (3) | | (25 | ) | | (42 | ) | | — |
| |
| Loss (Gain) on Asset Retirement Obligation Revisions | | 9 |
| | (25 | ) | | (42 | ) |
| Other, Net | | 35 |
| | 33 |
| | 77 |
| 83 |
| | 35 |
| | 33 |
|
| Total | | $ | 346 |
| | $ | 138 |
| | $ | 135 |
| $ | 214 |
| | $ | 50 |
| | $ | 138 |
|
| |
(1) | As part of the Saddle Butte Acquisition in first quarter 2018, we acquired certain contracts which include the purchase and sale of crude oil with third parties. In addition, we entered into certain transactions beginning in first quarter 2018 for the purchase of third-party natural gas and the subsequent sale of natural gas to other third parties. The natural gas is transported through firm transportation capacity we retained following the Marcellus Shale upstream divestiture in second quarter 2017 and is part of our mitigation efforts to utilize capacity and reduce our financial commitment. See Note 3. Segment Information6. Capitalized Exploratory Well Costs and Note 10. Marcellus Shale Firm Transportation CommitmentsUndeveloped Leasehold Costs. |
| |
(2) | Amounts relate to shortfalls in transporting or processing minimum volumes under certain financial 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) and 2016. |
| |
(3)
| Gains due to downward ARO revisions in locations where we have no remaining assets. See Note 8. Asset Retirement Obligations11. Exit Cost – Transportation Commitments. |
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Balance Sheet Information Other balance sheet information is as follows: | | | | | December 31, | December 31, |
| (millions) | | 2018 | | 2017 | 2019 | | 2018 |
| Accounts Receivable, Net | | | | | | | |
| Commodity Sales | | $ | 383 |
| | $ | 455 |
| $ | 446 |
| | $ | 383 |
|
Joint Interest Billings (1) | | 137 |
| | 207 |
| 164 |
| | 137 |
|
| Other | | 111 |
| | 103 |
| 128 |
| | 111 |
|
| Allowance for Doubtful Accounts | | (15 | ) | | (17 | ) | |
| Allowance | | (8 | ) | | (15 | ) |
| Total | | $ | 616 |
| | $ | 748 |
| $ | 730 |
| | $ | 616 |
|
| Other Current Assets | | |
| | |
| |
| | |
|
| Commodity Derivative Assets | | $ | 180 |
| | $ | — |
| $ | 14 |
| | $ | 180 |
|
| Inventories, Materials and Supplies | | 55 |
| | 66 |
| 59 |
| | 55 |
|
| Inventories, Crude Oil | | 12 |
| | 16 |
| |
Assets Held for Sale (2) | | 133 |
| | 629 |
| |
Restricted Cash (3) | | 3 |
| | 38 |
| |
| Prepaid Expenses and Other Assets, Current | | 35 |
| | 31 |
| |
Assets Held for Sale (1) | | 14 |
| | 133 |
|
| Prepaid Expenses and Other Current Assets | | 61 |
| | 50 |
|
| Total | | $ | 418 |
| | $ | 780 |
| $ | 148 |
| | $ | 418 |
|
| Other Noncurrent Assets | | | | | | | |
| Equity Method Investments | | $ | 286 |
| | $ | 305 |
| |
Customer-Related Intangible Assets, Net (4) | | 310 |
| | — |
| |
Equity Method Investments (2) | | $ | 1,066 |
| | $ | 286 |
|
Operating Lease Right-of-Use Assets (3) | | 227 |
| | — |
|
Customer-Related Intangible Assets, Net | | 278 |
| | 310 |
|
| Goodwill | | 110 |
| | 110 |
|
| Mutual Fund Investments | | 38 |
| | 57 |
| 27 |
| | 38 |
|
| Net Deferred Income Tax Asset | | 21 |
| | 25 |
| |
| Other Assets, Noncurrent | | 76 |
| | 74 |
| |
| Other Noncurrent Assets | | 126 |
| | 97 |
|
| Total | | $ | 731 |
| | $ | 461 |
| $ | 1,834 |
| | $ | 841 |
|
| Other Current Liabilities | | | | | | | |
| Production and Ad Valorem Taxes | | $ | 103 |
| | $ | 84 |
| $ | 118 |
| | $ | 103 |
|
| Commodity Derivative Liabilities | | 1 |
| | 58 |
| |
| Income Taxes Payable | | 22 |
| | 18 |
| |
| Asset Retirement Obligations | | 118 |
| | 51 |
| 84 |
| | 118 |
|
| Interest Payable | | 66 |
| | 67 |
| 74 |
| | 66 |
|
| Current Portion of Capital Lease Obligations | | 41 |
| | 61 |
| |
Liabilities Associated with Assets Held for Sale (2) | | 1 |
| | 55 |
| |
Operating Lease Liabilities (3) | | 88 |
| | — |
|
| Compensation and Benefits Payable | | 83 |
| | 98 |
| 126 |
| | 83 |
|
| Other Liabilities, Current | | 84 |
| | 86 |
| |
| Other Current Liabilities | | 229 |
| | 149 |
|
| Total | | $ | 519 |
| | $ | 578 |
| $ | 719 |
| | $ | 519 |
|
| Other Noncurrent Liabilities | | | | | | | |
| Deferred Compensation Liabilities | | $ | 147 |
| | $ | 197 |
| $ | 133 |
| | $ | 147 |
|
Asset Retirement Obligations | | 762 |
| | 824 |
| 730 |
| | 762 |
|
| Marcellus Shale Exit Cost Accrual | | 67 |
| | 76 |
| |
| Production and Ad Valorem Taxes | | 83 |
| | 69 |
| |
| Commodity Derivative Liabilities | | 26 |
| | 15 |
| |
| Other Liabilities, Noncurrent | | 80 |
| | 64 |
| |
Operating Lease Liabilities (3) | | 164 |
| | — |
|
Firm Transportation Exit Cost Accrual (4) | | 129 |
| | 67 |
|
| Other Noncurrent Liabilities | | 222 |
| | 189 |
|
| Total | | $ | 1,165 |
| | $ | 1,245 |
| $ | 1,378 |
| | $ | 1,165 |
|
| |
(1) | We bill partners for their shareAmounts relate to divestitures of expenses of joint venture projects for which we are the operator. These projects, especially thosenon-core assets and acreage in deepwater or remote international locations, can be very capital cost intensive. Our receivables from joint interest billings decreased significantly in 2018 due to the second quarter 2018 sale of our Gulf of Mexico offshore assets.Reeves County, Texas. See Note 4. Acquisitions and Divestitures. |
| |
(2) | Assets held for sale at December 31, 2018 include certain provedSee Note 5. Equity Method Investments. |
| |
(3) | Amounts relate to assets and unproved non-core acreageliabilities recorded as a result of ASC 842 adoption. See Note 9. Leases. |
| |
(4) | See Note 11. Exit Cost – Transportation Commitmentsin Reeves County, Texas. Assets held for sale at December 31, 2017 include assets in the Greeley Crescent area of the DJ Basin, a 7.5% interest in the Tamar field, our investment in Southwest Royalties, Inc. acquired in the Clayton Williams Energy Acquisition, and the CONE investments, including. |
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
CONE Midstream and CONE Gathering. Liabilities associated with assets held for sale primarily represent ARO and other liabilities to be assumed by the purchaser. See Note 5. Acquisitions and Divestitures. | |
(3)
| Balance at December 31, 2018 represents amounts held for the divestiture of certain non-core acreage in the Delaware Basin and 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 5. Acquisitions and Divestitures. |
Reconciliation of Total Cash We define total cash as cash, cash equivalents and restricted cash. The following table provides a reconciliation of total cash:
| | | | | December 31, | | December 31, |
| (millions) | | 2018 | | 2017 | | 2019 | | 2018 |
| Cash and Cash Equivalents at Beginning of Period | | $ | 675 |
| | $ | 1,180 |
| | $ | 716 |
| | $ | 675 |
|
| Restricted Cash at Beginning of Period | | 38 |
| | 30 |
| | 3 |
| | 38 |
|
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | | $ | 713 |
| | $ | 1,210 |
| | $ | 719 |
| | $ | 713 |
|
| Cash and Cash Equivalents at End of Period | | $ | 716 |
| | $ | 675 |
| | $ | 484 |
| | $ | 716 |
|
| Restricted Cash at End of Period | | 3 |
| | 38 |
| | — |
| | 3 |
|
| Cash, Cash Equivalents, and Restricted Cash at End of Period | | $ | 719 |
| | $ | 713 |
| | $ | 484 |
| | $ | 719 |
|
A significant portion of our cash is located in foreign subsidiaries. The cash is denominated in US dollars and at certain times is 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.
Supplemental Cash Flow Information Supplemental statements of cash flow information areis as follows: | | | | | Year Ended December 31, | Year Ended December 31, |
| (millions) | | 2018 |
| 2017 |
| 2016 | 2019 |
| 2018 |
| 2017 |
| Cash Paid During the Year For | | | | | | | | | | | |
| Interest, Net of Amount Capitalized | | $ | 270 |
| | $ | 346 |
| | $ | 327 |
| |
Interest, Net of Amount Capitalized (1) | | $ | 208 |
| | $ | 270 |
| | $ | 346 |
|
| Income Taxes Paid, Net | | 172 |
| | 121 |
| | 236 |
| 76 |
| | 172 |
| | 121 |
|
| Non-Cash Financing and Investing Activities | | | | | | | |
| Increase in Capital Lease Obligations | | 14 |
| | — |
| | 5 |
| |
| |
(1) | Interest capitalized totaled $102 million in 2019, $73 million in 2018 and $49 million in 2017. |
See Note 9. Leases for supplemental cash flow information related to leases.
Significant Purchasers Non-affiliated purchasers who accounted for 10% or more of our commodity sales were as follows:
|
| | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Percentage of Crude Oil Sales | | | | | |
Shell (1) | 22 | % | | 22 | % | | 22 | % |
BP (2) | 18 | % | | 31 | % | | 15 | % |
| Percentage of Total Crude Oil, NGL & Natural Gas Sales | | | | | |
Shell (1) | 15 | % | | 14 | % | | 13 | % |
BP (2) | 14 | % | | 17 | % | | 10 | % |
| |
(1) | Includes sales to Shell Energy North America and Shell Trading (US) Company (collectively, Shell). |
| |
(2) | Includes sales to BP America Production, BP Energy Co and BP Products North America, Inc (collectively, BP). |
Both Shell and BP purchased crude oil and condensate domestically from our US onshore operations. No other single purchaser accounted for 10% or more of our commodity sales in 2019. We routinely monitor the credit worthiness of our purchasers. While we maintain credit insurance associated with certain purchasers, we do not carry credit insurance for all purchasers. We believe that the loss of any one significant purchaser would not have a material adverse effect on our financial position or results of operations as there are numerous potential purchasers of our US onshore production and generally production is sold under short-term contracts.
Note 3. Segment Information
We have the following reportable segments: United States (US onshore (Marcellus Shale until July 2017) and Gulf of Mexico (until April 2018)); Eastern Mediterranean (Israel and Cyprus); West Africa (Equatorial Guinea, Cameroon and Gabon); Other International (Suriname (until November 2018), Falkland Islands (until December 2018), Canada, Colombia and New Ventures); and Midstream. The Midstream segment includes the consolidated accounts of Noble Midstream Partners, US onshore equity method investments and other US onshore midstream assets.Partners.
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
The geographical reportable segments are in the business of crude oil and natural gas acquisition and exploration, development, and production (Oil and Gas Exploration and Production). The Midstream reportable segment develops, owns, and operates domestic midstream infrastructure assets, as well as invests in other financially attractive midstream projects, with current focus areas being the DJ and Delaware Basins. To assess the performance of Noble Energy's operating segments, theThe chief operating decision maker analyzes income (loss) before income taxes. Managementtaxes to assess the performance of Noble Energy's reportable segments as management believes income (loss) before income taxesthis measure provides useful information useful in assessing the Company's operating and financial performance across periods.
Expenses related to debt, such as interest and other debt-related costs, headquarters depreciation, corporate general and administrative expenses, exit costs and certain costs associated with mitigating the effects of our retained Marcellus Shale firm transportation agreements, are recorded at the corporate level. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 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 |
| Year Ended December 31, 2019 |
| Crude Oil Sales | $ | 2,736 |
| | $ | 2,437 |
| | $ | 6 |
| | $ | 293 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| NGL Sales | 354 |
| | 354 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Natural Gas Sales | 814 |
| | 345 |
| | 451 |
| | 18 |
| | — |
| | — |
| | — |
| | — |
|
| Total Crude Oil, NGL and Natural Gas Sales | 3,904 |
| | 3,136 |
| | 457 |
| | 311 |
| | — |
| | — |
| | — |
| | — |
|
| Sales of Purchased Oil and Gas | 389 |
| | 109 |
| | — |
| | — |
| | — |
| | 190 |
| | — |
| | 90 |
|
| Income (Loss) from Equity Method Investments and Other | 51 |
| | 8 |
| | — |
| | 61 |
| | — |
| | (18 | ) | | — |
| | — |
|
| Midstream Services Revenues - Third Party | 94 |
| | — |
| | — |
| | — |
| | — |
| | 94 |
| |
|
| | — |
|
| Intersegment Revenues | — |
| | — |
| | — |
| | — |
| | — |
| | 427 |
| | (427 | ) | | — |
|
| Total Revenues | 4,438 |
| | 3,253 |
| | 457 |
| | 372 |
| | — |
| | 693 |
| | (427 | ) | | 90 |
|
| Lease Operating Expense | 532 |
| | 460 |
| | 37 |
| | 76 |
| | — |
| | 4 |
| | (45 | ) | | — |
|
| Production and Ad Valorem Taxes | 175 |
| | 169 |
| | — |
| | — |
| | — |
| | 6 |
| | — |
| | — |
|
| Gathering, Transportation and Processing Expense | 417 |
| | 598 |
| | 1 |
| | — |
| | — |
| | 110 |
| | (292 | ) | | — |
|
| Other Royalty Expense | 13 |
| | 13 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total Production Expense | 1,137 |
| | 1,240 |
| | 38 |
| | 76 |
| | — |
| | 120 |
| | (337 | ) | | — |
|
| Exploration Expense | 202 |
| | 57 |
| | 109 |
| | 13 |
| | 23 |
| | — |
| | — |
| | — |
|
| Depreciation, Depletion and Amortization | 2,197 |
| | 1,907 |
| | 67 |
| | 83 |
| | 1 |
| | 104 |
| | (29 | ) | | 64 |
|
| Asset Impairments | 1,160 |
| | 1,160 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Cost of Purchased Oil and Gas | 431 |
| | 107 |
| | — |
| | — |
| | — |
| | 181 |
| | — |
| | 143 |
|
| Firm Transportation Exit Cost | 88 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 88 |
|
| Loss on Commodity Derivative Instruments | 143 |
| | 125 |
| | — |
| | 18 |
| | — |
| | — |
| | — |
| | — |
|
| Loss on Debt Extinguishment | 44 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 44 |
|
| (Loss) Income Before Income Taxes | (1,776 | ) | | (1,431 | ) | | 199 |
| | 164 |
| | (25 | ) | | 258 |
| | (55 | ) | | (886 | ) |
| Additions to Long-Lived Assets, Excluding Acquisitions | 2,408 |
| | 1,651 |
| | 505 |
| | 70 |
| | 20 |
| | 230 |
| | (92 | ) | | 24 |
|
| Additions to Equity Method Investments | 799 |
| | — |
| | 189 |
| | — |
| | — |
| | 610 |
| | — |
| | — |
|
| Property, Plant and Equipment, Net | 17,451 |
| | 11,859 |
| | 3,041 |
| | 793 |
| | 44 |
| | 1,721 |
| | (223 | ) | | 216 |
|
| Year Ended December 31, 2018 |
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
| | | | | | 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 |
| Year Ended December 31, 2018 | |
| Crude Oil Sales | $ | 2,945 |
| | $ | 2,548 |
| | $ | 7 |
| | $ | 390 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | 2,945 |
| | $ | 2,548 |
| | $ | 7 |
| | $ | 390 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| NGL Sales | 587 |
| | 587 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| 587 |
| | 587 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Natural Gas Sales | 929 |
| | 435 |
| | 473 |
| | 21 |
| | — |
| | — |
| | — |
| | — |
| 929 |
| | 435 |
| | 473 |
| | 21 |
| | — |
| | — |
| | — |
| | — |
|
| Total Crude Oil, NGL and Natural Gas Sales | 4,461 |
| | 3,570 |
| | 480 |
| | 411 |
| | — |
| | — |
| | — |
| | — |
| 4,461 |
| | 3,570 |
| | 480 |
| | 411 |
| | — |
| | — |
| | — |
| | — |
|
| Sales of Purchased Oil and Gas | 275 |
| | 20 |
| | — |
| | — |
| | — |
| | 142 |
| | — |
| | 113 |
| 275 |
| | 20 |
| | — |
| | — |
| | — |
| | 142 |
| | — |
| | 113 |
|
| Income from Equity Method Investees | 172 |
| | — |
| | — |
| | 132 |
| | — |
| | 40 |
| | — |
| | — |
| |
| Income from Equity Method Investments and Other | | 172 |
| | — |
| | — |
| | 132 |
| | — |
| | 40 |
| | — |
| | — |
|
| Midstream Services Revenues - Third Party | 78 |
| | — |
| | — |
| | — |
| | — |
| | 78 |
| | — |
| | — |
| 78 |
| | — |
| | — |
| | — |
| | — |
| | 78 |
| | — |
| | — |
|
| Intersegment Revenues | — |
| |
|
| |
|
| |
|
| |
|
| | 351 |
| | (351 | ) | |
|
| — |
| | — |
| | — |
| | — |
| | — |
| | 351 |
| | (351 | ) | | — |
|
| Total Revenues | 4,986 |
| | 3,590 |
| | 480 |
| | 543 |
| | — |
| | 611 |
| | (351 | ) | | 113 |
| 4,986 |
| | 3,590 |
| | 480 |
| | 543 |
| | — |
| | 611 |
| | (351 | ) | | 113 |
|
| Lease Operating Expense | 576 |
| | 480 |
| | 26 |
| | 97 |
| | — |
| | — |
| | (27 | ) | | — |
| 576 |
| | 480 |
| | 26 |
| | 97 |
| | — |
|
| — |
| | (27 | ) | | — |
|
| Production and Ad Valorem Taxes | 190 |
| | 184 |
| | — |
| | — |
| | — |
| | 6 |
| | — |
| | — |
| 190 |
| | 184 |
| | — |
| | — |
| | — |
| | 6 |
| | — |
| | — |
|
| Gathering, Transportation and Processing Expense | 393 |
| | 533 |
| | — |
| | — |
| | — |
| | 95 |
| | (235 | ) | | — |
| 393 |
| | 533 |
| | — |
| | — |
| | — |
| | 95 |
| | (235 | ) | | — |
|
| Other Royalty Expense | 38 |
| | 38 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| 38 |
| | 38 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total Production Expense | 1,197 |
| | 1,235 |
| | 26 |
| | 97 |
| | — |
| | 101 |
| | (262 | ) | | — |
| 1,197 |
| | 1,235 |
| | 26 |
| | 97 |
| | — |
| | 101 |
| | (262 | ) | | — |
|
| Exploration Expense | 129 |
| | 48 |
| | 7 |
| | 6 |
| | 68 |
| | — |
| | — |
| | — |
| 129 |
| | 48 |
| | 7 |
| | 6 |
| | 68 |
| | — |
| | — |
| | — |
|
| DD&A | 1,934 |
| | 1,642 |
| | 60 |
| | 115 |
| | 2 |
| | 87 |
| | (20 | ) | | 48 |
| |
| Depreciation, Depletion and Amortization | | 1,934 |
| | 1,642 |
| | 60 |
| | 115 |
| | 2 |
| | 87 |
| | (20 | ) | | 48 |
|
| (Gain) Loss on Divestitures, Net | (843 | ) | | 36 |
| | (376 | ) | | — |
| | — |
| | (503 | ) | | — |
| | — |
| (843 | ) | | 36 |
| | (376 | ) | | — |
| | — |
| | (503 | ) | | — |
| | — |
|
| Asset Impairments | 206 |
| | 169 |
| | — |
| | — |
| | — |
| | 37 |
| | — |
| | — |
| 206 |
| | 169 |
| | — |
| | — |
| | — |
| | 37 |
| | — |
| | — |
|
| Goodwill Impairment | 1,281 |
| | 1,281 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| 1,281 |
| | 1,281 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Cost of Purchased Oil and Gas | 296 |
| | 20 |
| | — |
| | — |
| | — |
| | 136 |
| | — |
| | 140 |
| 296 |
| | 20 |
| | — |
| | — |
| | — |
| | 136 |
| | — |
| | 140 |
|
| Gain on Asset Retirement Obligation Revisions | (25 | ) | | — |
| | (8 | ) | | — |
| | (17 | ) | | — |
| | — |
| | — |
| |
| Gain on Asset Retirement Obligation Revision | | (25 | ) | | — |
| | (8 | ) | | — |
| | (17 | ) | | — |
| | — |
| | — |
|
| (Gain) Loss on Commodity Derivative Instruments | (63 | ) | | (70 | ) | | — |
| | 7 |
| | — |
| | — |
| | — |
| | — |
| (63 | ) | | (70 | ) | | — |
| | 7 |
| | — |
| | — |
| | — |
| | — |
|
| Income (Loss) Before Income Taxes | 140 |
| | (875 | ) | | 742 |
| | 305 |
| | (53 | ) | | 726 |
| | (60 | ) | | (645 | ) | 140 |
| | (875 | ) | | 742 |
| | 305 |
| | (53 | ) | | 726 |
| | (60 | ) | | (645 | ) |
| Additions to Long Lived Assets | 3,253 |
| | 2,115 |
| | 671 |
| | 12 |
| | — |
| | 521 |
| | (91 | ) | | 25 |
| |
| Additions to Long Lived Assets, Excluding Acquisitions | | 3,253 |
| | 2,115 |
| | 671 |
| | 12 |
| | — |
| | 521 |
| | (91 | ) | | 25 |
|
| Property, Plant and Equipment, Net | 18,419 |
| | 13,044 |
| | 2,630 |
| | 805 |
| | 37 |
| | 1,742 |
| | (145 | ) | | 306 |
| 18,419 |
| | 13,044 |
| | 2,630 |
| | 805 |
| | 37 |
| | 1,742 |
| | (145 | ) | | 306 |
|
Year Ended December 31, 2017 | | Crude Oil Sales | $ | 2,346 |
| | $ | 1,993 |
| | $ | 6 |
| | $ | 347 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | 2,346 |
| | $ | 1,993 |
| | $ | 6 |
| | $ | 347 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| NGL Sales | 493 |
| | 493 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| 493 |
| | 493 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Natural Gas Sales | 1,221 |
| | 670 |
| | 528 |
| | 23 |
| | — |
| | — |
| | — |
| | — |
| 1,221 |
| | 670 |
| | 528 |
| | 23 |
| | — |
| | — |
| | — |
| | — |
|
| Total Crude Oil, NGL and Natural Gas Sales | 4,060 |
| | 3,156 |
| | 534 |
| | 370 |
| | — |
| | — |
| | — |
| | — |
| 4,060 |
| | 3,156 |
| | 534 |
| | 370 |
| | — |
| | — |
| | — |
| | — |
|
| Income from Equity Method Investees | 177 |
| | — |
| | — |
| | 120 |
| | — |
| | 57 |
| | — |
| | — |
| |
| Income from Equity Method Investments and Other | | 177 |
| | — |
| | — |
| | 120 |
| | — |
| | 57 |
| | — |
| | — |
|
| Midstream Services Revenues - Third Party | 19 |
| | — |
| | — |
| | — |
| | — |
| | 19 |
| | — |
| | — |
| 19 |
| | — |
| | — |
| | — |
| | — |
| | 19 |
| | — |
| | — |
|
| Intersegment Revenues | — |
| | — |
| | — |
| | — |
| | — |
| | 277 |
| | (277 | ) | | — |
| — |
| | — |
| | — |
| | — |
| | — |
| | 277 |
| | (277 | ) | | — |
|
| Total Revenues | 4,256 |
| | 3,156 |
| | 534 |
| | 490 |
| | — |
| | 353 |
| | (277 | ) | | — |
| |
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 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 |
| Lease Operating Expense | 571 |
| | 466 |
| | 29 |
| | 90 |
| | — |
|
| — |
| | (14 | ) | | — |
|
| Production and Ad Valorem Taxes | 118 |
| | 115 |
| | — |
| | — |
| | — |
| | 3 |
| | — |
| | — |
|
| Gathering, Transportation and Processing Expense | 432 |
| | 550 |
| | — |
| | — |
| | — |
| | 70 |
| | (188 | ) | | — |
|
| Other Royalty Expense | 20 |
| | 20 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total Production Expense | 1,141 |
| | 1,151 |
| | 29 |
| | 90 |
| | — |
| | 73 |
| | (202 | ) | | — |
|
| Exploration Expense | 188 |
| | 102 |
| | 2 |
| | 5 |
| | 79 |
| | — |
| | — |
| | — |
|
| DD&A | 2,053 |
| | 1,739 |
| | 76 |
| | 146 |
| | 4 |
| | 30 |
| | (5 | ) | | 63 |
|
| Loss on Marcellus Shale Upstream Divestiture and Other | 2,379 |
| | 2,286 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 93 |
|
| Gain on Divestitures, Net | (326 | ) | | (325 | ) | | (1 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
Asset Impairments | 70 |
| | 63 |
| | — |
| | — |
| | 7 |
| | — |
| | — |
| | — |
|
| Clayton Williams Energy Acquisition Expenses | 100 |
| | 100 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Gain on Asset Retirement Obligation Revision | (42 | ) | | — |
| | — |
| | — |
| | (42 | ) | | — |
| | — |
| | — |
|
| (Gain) Loss on Commodity Derivative Instruments | (63 | ) | | (92 | ) | | — |
| | 29 |
| | — |
| | — |
| | — |
| | — |
|
| Loss on Debt Extinguishment | 98 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 98 |
|
| (Loss) Income Before Income Taxes | (2,191 | ) | | (2,365 | ) | | 413 |
| | 203 |
| | (54 | ) | | 233 |
| | (62 | ) | | (559 | ) |
| Additions to Long Lived Assets | 2,851 |
| | 1,994 |
| | 411 |
| | 34 |
| | (34 | ) | | 423 |
| | (79 | ) | | 102 |
|
| Property, Plant and Equipment, Net | 17,502 |
| | 13,348 |
| | 2,005 |
| | 863 |
| | 25 |
| | 1,027 |
| | (74 | ) | | 308 |
|
| Year Ended December 31, 2016 |
| Crude Oil Sales | $ | 1,854 |
| | $ | 1,439 |
| | $ | 5 |
| | $ | 410 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| NGL Sales | 296 |
| | 296 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Natural Gas Sales | 1,239 |
| | 681 |
| | 535 |
| | 23 |
| | — |
| | — |
| | — |
| | — |
|
| Total Crude Oil, NGL and Natural Gas Sales | 3,389 |
| | 2,416 |
| | 540 |
| | 433 |
| | — |
| | — |
| | — |
| | — |
|
| Income from Equity Method Investees | 102 |
| | — |
| | — |
| | 50 |
| | — |
| | 52 |
| | — |
| | — |
|
| Intersegment Revenues | — |
| | — |
| | — |
| | — |
| | — |
| | 200 |
| | (200 | ) | | — |
|
| Total Revenues | 3,491 |
| | 2,416 |
| | 540 |
| | 483 |
| | — |
| | 252 |
| | (200 | ) | | — |
|
| Lease Operating Expense | 542 |
| | 418 |
| | 37 |
| | 105 |
| | — |
| | — |
| | (18 | ) | | — |
|
| Production and Ad Valorem Taxes | 57 |
| | 55 |
| | — |
| | — |
| | — |
| | 2 |
| | — |
| | — |
|
| Gathering, Transportation and Processing Expense | 480 |
| | 564 |
| | — |
| | — |
| | — |
| | 44 |
| | (128 | ) | | — |
|
| Other Royalty Expense | 21 |
| | 21 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total Production Expense | 1,100 |
| | 1,058 |
| | 37 |
| | 105 |
| | — |
| | 46 |
| | (146 | ) | | — |
|
| Exploration Expense | 925 |
| | 245 |
| | 34 |
| | 483 |
| | 163 |
| | — |
| | — |
| | — |
|
| DD&A | 2,454 |
| | 2,103 |
| | 81 |
| | 205 |
| | 6 |
| | 19 |
| | — |
| | 40 |
|
| (Gain) Loss on Divestitures, Net | (238 | ) | | 23 |
| | (261 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
| Asset Impairments | 92 |
| | — |
| | 88 |
| | — |
| | 4 |
| | — |
| | — |
| | — |
|
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
| | | | | | 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 |
| Loss on Commodity Derivative Instruments | 139 |
| | 126 |
| | — |
| | 13 |
| | — |
| | — |
| | — |
| | — |
| |
| Total Revenues | | 4,256 |
| | 3,156 |
| | 534 |
| | 490 |
| | — |
| | 353 |
| | (277 | ) | | — |
|
| Lease Operating Expense | | 571 |
| | 466 |
| | 29 |
| | 90 |
| | — |
| | — |
| | (14 | ) | | — |
|
| Production and Ad Valorem Taxes | | 118 |
| | 115 |
| | — |
| | — |
| | — |
| | 3 |
| | — |
| | — |
|
| Gathering, Transportation and Processing Expense | | 432 |
| | 550 |
| | — |
| | — |
| | — |
| | 70 |
| | (188 | ) | | — |
|
| Other Royalty Expense | | 20 |
| | 20 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total Production Expense | | 1,141 |
| | 1,151 |
| | 29 |
| | 90 |
| | — |
| | 73 |
| | (202 | ) | | — |
|
| Exploration Expense | | 188 |
| | 102 |
| | 2 |
| | 5 |
| | 79 |
| | — |
| | — |
| | — |
|
| Depreciation, Depletion and Amortization | | 2,053 |
| | 1,739 |
| | 76 |
| | 146 |
| | 4 |
| | 30 |
| | (5 | ) | | 63 |
|
| Loss on Marcellus Shale Upstream Divestiture and Other | | 2,379 |
| | 2,286 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 93 |
|
| Gain on Divestitures, Net | | (326 | ) | | (325 | ) | | (1 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
| Asset Impairments | | 70 |
| | 63 |
| | — |
| | — |
| | 7 |
| | — |
| | — |
| | — |
|
| Clayton Williams Energy Acquisition Expenses | | 100 |
| | 100 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Gain on Asset Retirement Obligation Revision | | (42 | ) | | — |
| | — |
| | — |
| | (42 | ) | | — |
| | — |
| | — |
|
| (Gain) Loss on Commodity Derivative Instruments | | (63 | ) | | (92 | ) | | — |
| | 29 |
| | — |
| | — |
| | — |
| | — |
|
| Loss on Debt Extinguishment | | 98 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 98 |
|
| (Loss) Income Before Income Taxes | (1,772 | ) | | (1,277 | ) | | 543 |
| | (338 | ) | | (199 | ) | | 176 |
| | (51 | ) | | (626 | ) | (2,191 | ) | | (2,365 | ) | | 413 |
| | 203 |
| | (54 | ) | | 233 |
| | (62 | ) | | (559 | ) |
| Additions to Long Lived Assets | 1,526 |
| | 1,353 |
| | 88 |
| | 54 |
| | (6 | ) | | 58 |
| | (53 | ) | | 32 |
| |
| Additions to Long Lived Assets, Excluding Acquisitions | | 2,851 |
| | 1,994 |
| | 411 |
| | 34 |
| | (34 | ) | | 423 |
| | (79 | ) | | 102 |
|
| Property, Plant and Equipment, Net | 18,548 |
| | 14,755 |
| | 1,872 |
| | 980 |
| | 15 |
| | 594 |
| | — |
| | 332 |
| 17,502 |
| | 13,348 |
| | 2,005 |
| | 863 |
| | 25 |
| | 1,027 |
| | (74 | ) | | 308 |
|
| |
(1) | Intersegment eliminations related to income (loss) before income taxes are the result of Midstream expenditures. These costsCertain of these expenditures 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,accounting. Other expenditures are presented as production expense. Intercompany revenues and expenses are eliminated upon consolidation. |
The largest single non-affiliated purchasers of our production were as follows:
|
| | | | | | |
| | | Percentage of Crude Oil Sales | | Percentage of Total Oil, NGL & Gas Sales |
| Year Ended December 31, 2018 | | | | |
BP (1) | | 31 | % | | 17 | % |
Shell (2) | | 22 | % | | 14 | % |
| Year Ended December 31, 2017 | | | | |
BP (1) | | 15 | % | | 10 | % |
Shell (2) | | 22 | % | | 13 | % |
| Year Ended December 31, 2016 | | | | |
| Glencore Energy UK Ltd | | 22 | % | | 12 | % |
Shell (2) | | 24 | % | | 13 | % |
(1) Includes sales to BP North American Funding Company, BP Company Commercial and/or BP Company.
(2) Includes sales to Shell Trading (US) Company and/or Shell International Trading and Shipping Limited.
Both BP and Shell purchased crude oil and condensate domestically from our US onshore operations and from our Gulf of Mexico operations prior to selling the Gulf of Mexico assets in second quarter 2018. No other single purchaser accounted for 10% or more of crude oil, NGL and natural gas sales in 2018. We maintain credit insurance associated with specific purchasers and believe that the loss of any one purchaser would not have a material effect on our financial position or results of operations as there are numerous potential purchasers of our production.
Note. 4. Revenue from Contracts with Customers
Our revenue is derived from the sale of crude oil, NGL and natural gas production, primarily to crude oil refining companies, midstream marketing companies, marketers, industrial companies, electric utility companies, independent power producers and cogeneration facilities, among others. We account for revenue in accordance with ASC 606, Revenue from Contracts with Customers (ASC 606), which we adopted on January 1, 2018 using the modified retrospective method. Under ASC 606, performance obligations are the unit of account and generally represent distinct goods or services that are promised to customers. For sales of crude oil, NGLs and natural gas, each unit sold is generally considered a distinct good and the related performance obligation is generally satisfied at a point in time. We recognize our sales revenues at a point in time and upon delivery to a customer at the contractually stated price and for the quantity of product delivered. In Israel, because our contracts are long-term arrangements, we recognize revenues from the sale of natural gas over the life of the contract based on the quantity of natural gas delivered.
ASC 606 provides additional clarification related to principal versus agent considerations. Under this guidance, we record revenue on a gross basis if we control a promised good or service before transferring it to a customer (acting as principal). For example, gathering, processing, transportation and fractionation costs incurred before transfer of control to the customer at the tailgate of a plant are accounted for as fulfillment costs and are presented as a component of gathering, transportation and processing expense in our consolidated statements of operations. On the other hand, we record revenue on a net basis if our role is to arrange for another entity to provide the goods or services (acting as agent). For example, costs incurred after control over the product has transferred to the customer, such as at the wellhead or inlet of a plant, are recorded as a reduction of the transaction price received within revenue.
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Certain of our contracts for the sale of commodities contain embedded derivatives. We have elected the normal purchases and normal sales scope exception as provided by ASC 815, Derivatives and Hedging, and will account for such contracts in accordance with ASC 606.
In the US, we enter into marketing agreements with our non-operating partners to market and sell their share of production to third parties. We have determined that we act as an agent in such arrangements and account for such arrangements on a net basis.
ASC 606 adoption did not have an impact on the opening balance of retained earnings. The adoption impact on revenues and expenses for 2018 was less than $1 million and did not affect operating or net income or operating cash flows. The comparative information for the prior period has not been recast and continues to be reported under the accounting standards in effect for the period. Adoption of the new standard did not impact our financial position, and we do not expect that it will do so going forward. See Note 3. Segment Information for disaggregation of revenue by commodity and geographic location.Changes to the presentation of commodity sales revenue and production expense resulted from our assessment of certain contractual arrangements under principal versus agent guidance and assessment of control under ASC 606. In particular, we have determined that the processor is our customer with regard to the sale of natural gas at the wellhead or the sale of NGLs at the tailgate. This is a change from previous conclusions reached under principal versus agent guidance per ASC 605, Revenue Recognition, where we previously determined that we retained control over our production until the sale to the end customer in the downstream markets. As such, effective January 1, 2018, revenues and expenses are presented on a net basis within revenues in our consolidated statements of operations at the time control over production is transferred to the processor under these arrangements.
Following the control model in ASC 606, we determined that we remain the principal in arrangements with end customers, such as when we take product in-kind at the tailgate and when we are directly responsible for the transportation and marketing of our production to downstream customers. In such arrangements, we record NGL and natural gas sales and production expense on a gross basis.
Our commodity sales contracts in the US are index-based and, thus, include variable consideration. In accordance with ASC 606, we allocate variable consideration (market price) to the distinct commodities transferred in the period, but not to the future obligations to deliver production. Such allocation represents the amount of consideration to which we are entitled for deliveries of our commodities to-date and represents the value of product delivered to the customer. Therefore, our revenue is recognized at the time of delivery and is the product of the volume delivered and the index-based price for the period.
The following is a summary of our types of revenue arrangements by commodity and geographic location.
Exploration and Production Revenue Arrangements
Crude Oil Sale Arrangements – USWe sell the majority of our US crude oil productionunder short-term contracts at market-based prices, adjusted for location, quality and transportation charges. Market-based pricing is based on the price index applicable for the location of the sale.
We sell our crude oil production either at the lease location or to downstream customers. Crude oil production at the lease location is sold through netback arrangements, under which we sell crude oil net of transportation costs incurred by the purchaser. We record revenue, net, at the lease location when the customer receives delivery of the product.
When we move our crude oil production from the lease location to the downstream markets in the US, we incur gathering and transportation costs, which we consider contract fulfillment activities. Such costs are reported as expense within gathering, transportation and processing expense in the consolidated statements of operations. Revenue from the sale of crude oil to downstream customers is recognized upon delivery, as specified in the contract, when control of the product has transferred to the customer.
In second quarter 2018, we entered into a long-term contract to sell firm quantities of crude oil under index-based prices adjusted by applicable fees, including transportation, insurance, and marketing.
Crude Oil Buy/Sell Transactions – US We enter into buy/sell arrangements that effect a change in location and/or grade with required repurchase of crude oil at a delivery point. The sale and repurchase of crude oil is settled at the same contractually fixed price (before application of transportation and grade deductions) on a net basis. We account for these transactions on a net basis, in accordance with ASC 845, Nonmonetary Transactions. We record the residual transportation fee as transportation expense within gathering, transportation and processing expense in the consolidated statements of operations.
Crude Oil Sale Arrangements – West AfricaOur share of crude oil and condensate from the Aseng, Alen and Alba fields is sold at market-based prices to Glencore Energy UK Ltd. (Glencore Energy). Crude oil is priced at a Dated Brent FOB net realized price achieved by Glencore Energy and is adjusted by applicable fees, including transportation, insurance, and marketing. We recognize revenue on the sale of crude oil to Glencore Energy at the time crude oil cargo is loaded onto the
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
tanker and control transfers to Glencore Energy. We record revenue at the realized price received from Glencore Energy, net of applicable fees.
Natural Gas and NGLs Sale Arrangements – US Certain of our commodity contracts in the US are for the sale of natural gas to processors at prevailing market prices. We evaluate the contract terms of these arrangements to determine whether the processor is a service provider or a customer on a contract by contract basis. In arrangements where we determine that we sold our product to the processor, we treat the processor as a customer and record revenue when the processor takes physical possession of the natural gas and NGLs and in the amount of proceeds expected to be received, net of any fees or deductions charged by the processor.
In other natural gas processing arrangements, we receive natural gas and NGL products "in-kind" after processing at the tailgate of the plant. In these arrangements, we are responsible for the transportation, fractionation and marketing costs of our production. In such cases, where we have determined that the processor is a service provider, we record the sale of natural gas and NGLs and applicable gathering, processing, transportation and fractionation fees on a gross basis at the time the product is delivered to the end customer.
Natural Gas Purchase and Sale Arrangements – USWeenter into purchase transactions and separate sale transactions with third parties at prevailing market prices to mitigate unutilized pipeline transportation commitments, primarily related to retained Marcellus Shale firm transportation contracts. 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.
Natural Gas Sale Arrangements – West Africa We sell our share of natural gas production from the Alba field under a long-term contract for $0.25 per MMBtu to a methanol plant, a liquefied petroleum gas (LPG) plant, a liquefied natural gas (LNG) plant and a power generation plant. We recognize revenue upon transfer of control of product to these processors.
Natural Gas Sale Arrangements – Israel Our natural gas sales in Israel are primarily based on long-term contracts with fixed volume commitments over the life of the arrangements. Our performance obligations for the sale of natural gas are satisfied over time using production output to measure progress. The nature of these contracts gives rise to several types of variable consideration, including index-based annual price escalations, commodity-based index pricing, tiered pricing and sales price discounts in periods of volume deficiencies. Additionally, the majority of our sales contracts contain take-or-pay provisions where the customers are required to purchase a contractual minimum over varying time periods. Where the variable consideration is related to market-based pricing or index-based escalations of a fixed base price, we have elected the variable consideration allocation exception pursuant to ASC 606. We record revenue related to the volumes delivered at the contract price at the time of delivery. To date, there have been no material impacts of variability in consideration due to tiered pricing, take-or-pay provisions and/or volume deficiency discounts. We believe that any variability due to future sales price adjustments associated with potential volume deficiencies will not have a significant impact on our financial position or results of operations.
Transaction Price Allocated to Remaining Performance Obligations – Israel Remaining performance obligations represent the transaction price of firm sales arrangements for which volumes have not been delivered. Pursuant to ASC 606, short and long-term interruptible contracts and long-term dedicated production agreements are excluded from the disclosure due to uncertainty associated with estimating future production volumes and future market prices. However, certain of our Tamar natural gas sales contracts in Israel have fixed annual sales volumes and fixed base pricing with annual index escalations. The following table includes estimated revenues based upon those certain agreements with fixed minimum take-or-pay sales volumes. Our actual future sales volumes under these agreements may exceed future minimum volume commitments. |
| | | | | | | | | |
| (millions) | 2019 | 2020 | Total |
Natural Gas Revenues (1) | $ | 137 |
| $ | 169 |
| $ | 306 |
|
| |
(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
Service 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 ArrangementsIn first quarter 2018, Noble Midstream Partners acquired an interest in Black Diamond which completed the Saddle Butte Acquisition of a large-scale integrated gathering system and associated third-party
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| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
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.
Note 5.4. Acquisitions and Divestitures
Year Ended December 31, 2019
Divestiture of Reeves County AssetsIn February 2019, we sold approximately 13,000 net proved and unproved non-core acres in the Reeves County, Texas area of the Delaware Basin. We maintain an ongoing portfolio management programreceived cash consideration of approximately $131 million, recognizing 0 gain or loss on the sale.
Asset Sale to Noble Midstream PartnersIn November 2019, we sold substantially all of our remaining midstream interests and have engagedassets to Noble Midstream Partners. The value of the transaction, which also included the sale of our incentive distribution rights, totaled approximately $1.6 billion, comprised of $670 million of cash and 38.5 million of newly issued Noble Midstream Partners common units, valued at approximately $930 million. Noble Midstream Partners funded the cash portion of the consideration through $420 million of borrowings on the Noble Midstream Services Revolving Credit Facility (defined below) and approximately $250 million in various transactions over recent years.gross proceeds from a private placement of approximately 12 million common units. At closing, we owned approximately 56.5 million common units, or 63%, of the outstanding units of Noble Midstream Partners. We are subject to a post-closing 180-day lock-up period applicable to the common units received. Sales proceeds were used to repay amounts outstanding under our commercial paper program. As we continue to consolidate Noble Midstream Partners, the activities related to these assets will continue to be reflected within our Midstream segment.
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| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Year Ended December 31, 2018
Divestiture of Gulf of Mexico Assets On February 15, 2018, we announced that we had signed a definitive agreement to sellWe sold substantially all of our Gulf of Mexico assets, including all of our interests in producing properties and undeveloped acreage, for cash consideration of $480 million, along with the assumption, by the purchaser, of all abandonment obligations associated with the properties. As a result, weproperties sold. We recorded impairment expense of $168 million during first quarter 2018.
In second quarter 2018, we closed the transaction with an effective date of January 1, 2018. After consideration of customary closing adjustments, to date we have We received net proceeds of approximately $384 million and recorded a loss of $24 million.
In addition, a cumulative contingent payment of up to $100 million is payable to us in the period after the closing of the transaction, beginning third quarter 2018, through the end of 2022, determined quarterly, at a rate of $2 per barrel produced by these assets when the average purchase price for Light Louisiana Sweet (LLS) crude oil exceeds $63 per barrel, and if produced crude oil volumes exceed certain minimum thresholds. As of December 31, 2018, $3 million has been accrued related to the contingent payment. upon close.
Divestiture of 7.5% Interest in Tamar Field On March 14,In first quarter 2018, we closed the sale ofsold a 7.5% working interest in the Tamar field to Tamar Petroleum Ltd. (Tamar Petroleum), a publicly traded entity on the Tel Aviv Stock Exchange (TASE: TMRP). Total consideration included cash of $484 million and 38.5 million shares of Tamar Petroleum shares that had a publicly traded value of $224 million. The transaction had an effective date of January 1, 2018 and, after consideration of closing adjustments and before consideration of taxes, we received $484 million of cash. Total consideration received from the sale was applied to the field's basis and resulted in the recognition of a pre-tax gain of $376 million. We incurred tax expense of $86 million in connection with the transaction.
The Tamar Petroleum shares were subject to certain temporary lock-up provisions and had no voting rights. Due to the lock-up provisions associated with the Tamar Petroleum shares, we initially attributed $190 million of fair value to the shares, or 15% lowerless than the publicly traded value on the TASE. These shares were accounted for at fair value and we recorded decreases in fair value of $27 million and dividend income of $31 million during 2018. These amounts are included in other non-operating (income) expense, net, in our consolidated statements of operations.
In fourth quarter 2018, we sold 38.5 million shares ofthe Tamar Petroleum shares in over the counter transactions for pre-tax proceeds of $163 million, net of transaction expenses. Upon sale, voting rights were restored and granted to the third parties. The sales of the 7.5% working interest in the Tamar field and of the Tamar Petroleum shares are in accordance with the terms of the Israel Natural Gas Framework (Framework) that requires us to reduce our ownership interest in the Tamar field from 32.5% to 25% by year-end 2021.
Divestiture of Southwest Royalties In January 2018, we closed the sale ofsold our investment in Southwest Royalties, Inc. (Southwest Royalties), a subsidiary of Clayton Williams Energy, Inc. (Clayton Williams Energy), which we acquired in the 2017 acquisition of Clayton Williams Energy (Clayton Williams Energy Acquisition) in 2017.. We received proceeds of $60 million, resulting in no0 gain or loss recognition on the sale of these assets.
Divestiture of Marcellus Shale CONE Gathering In January 2018, we closed the sale of our 50% interest in CONE Gathering LLC (CONE Gathering) to CNX Resources Corporation. CONE Gathering owns the general partner of CNX Midstream Partners LP (CNX Midstream Partners, NYSE: CNXM). We received proceeds of $309 million in cash and recognized a pre-tax gain of $196 million.
After the sale, we held 21.7 million common units, representing a 34.1% limited partner interest, in CNX Midstream Partners. During 2018, we sold our 21.7 million common units, receiving net proceeds of approximately $387 million, and recognized a gain of $307 million. The investment was previously accounted for under the equity method of accounting.
Divestiture of Greeley Crescent Assets In September 2018, we closed the sale ofsold assets in the Greeley Crescent area of the DJ Basin and received proceeds of $68 million, resulting in no0 gain or loss recognition on the sale of these assets.
Divestiture of Non-Core Delaware Basin Acreage In December 2018, we closed the sale ofsold certain non-core acreage in the Delaware Basin, receiving proceeds of $63 million, resulting in a pre-tax loss of $16 million.
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DJ Acreage Exchange We closed a cashless acreage exchange in the DJ Basin receiving approximately 12,900 net undeveloped acres within core areas of our Mustang and Wells Ranch positions in exchange for approximately 12,300 net undeveloped acres in non-core areas of Mustang and Wells Ranch. NoNaN gain or loss was recognized.
Noble Midstream Partners Saddle Butte AcquisitionOnIn January 31, 2018, Noble Midstream Partners acquired a 54.4% inand its partner formed Black Diamond Gathering LLC (Black Diamond), an entity formed by Black Diamond Gathering Holdings LLC, a wholly-owned subsidiary of Noble Midstream Partners, and Greenfield to acquire Saddle Butte Rockies Midstream, LLC (Greenfield),and affiliates, which completed the acquisition of Saddle Butte from Saddle Butte Pipeline II, LLC (Saddle Butte Acquisition). Saddle Butte ownedown a large-scale integrated gathering system located in the DJ Basin, which we subsequently renamedBasin. Consideration for the Black Diamond gathering system.
Considerationacquisition totaled $681 million, which included $663 million of cash and assumption of $18 million of liabilities. GreenfieldOur partner funded approximately $343 million of the purchase price, which is reflected as a contribution from noncontrolling interest within our consolidated statement of shareholders' equity, and Noble Midstream Partners funded the remainder. We consolidate Black Diamond as a VIE and reflect the third-party ownership within noncontrolling interest within our consolidated statement of equity.
This transaction wasWe accounted for the transaction as a business combination using the acquisition method. Themethod and allocated the total purchase price was allocated to assets acquired and liabilities assumed based on the fair valuevalues at the acquisition date. We have recognized goodwill for the amount of the purchase price exceeding the fair value of the assets acquired. Allocated fair valuevalues included: $206 million to property, plant and equipment; $340 million to customer-related intangible assets (acquired customer contracts); and $110 million to implied goodwill. Noble Midstream Partners has completed
We own a 54.4% interest in Black Diamond and consolidate the purchase price allocation related to this acquisition.
Other Acquisitions and Divestitures During 2018, we closed onentity as a VIE, reflecting the acquisition of other smaller US onshore properties for total cash consideration of $3 million. We also closed the sale of certain other smaller US onshore proved and unproved properties and received total cash consideration of $81 million, recording a gain of $4 million.
Subsequent Events In first quarter 2019, we closed the sale of certain proved and unproved non-core acreage totaling approximately 13,000 net acresthird-party ownership within noncontrolling interests in Reeves County, Texas. We received cash consideration of $132 million, recognizing no gain or loss on the sale. As of December 31, 2018, the assets and related liabilities associated with this acreage were considered held for sale and were recorded within other current assets and other current liabilities on our consolidated balance sheets.
In first quarter 2019, Noble Midstream Partners exercised and closed an option with EPIC Midstream Holdings, LP (EPIC) to acquire a 15% equity interest in the EPIC Y-Grade Pipeline. It also exercised an option to acquire a 30% equity interest in the EPIC Crude Oil Pipeline, for which closing is anticipated to occur later in first quarter 2019, subject to certain conditions precedent.statements of shareholders' equity.
Year Ended December 31, 2017
Clayton Williams Energy AcquisitionOn April 24, 2017, weWe completed the Clayton Williams Energy Acquisition. Clayton Williams Energy's resultsAcquisition on April 24, 2017. Total consideration of operations since the acquisition date are$2.5 billion included in our consolidated statementcash consideration of operations. The acquisition was effected through$637 million and proceeds from the issuance of approximately 56 million shares of Noble Energy common stock with a fair value of approximately $1.9 billion and cash consideration of $637 million, for total consideration of approximately $2.5 billion, inbillion. In exchange, forwe received all outstanding Clayton Williams Energy shares, including stock options, restricted stock awards and warrants.
The closing price of our stock on the New York Stock Exchange (NYSE) was $34.17 on April 24, 2017. In connection with the transaction, we borrowed $1.3 billion under our Revolving Credit Facility (defined below) to fund the cash portion of the acquisition consideration, redeem outstanding Clayton Williams Energy debt, pay associated make-whole premiums and pay related fees and expenses. See Note 9. Long-Term Debt.The acquired assets included 71,000 highly contiguous net acres in the core of the Delaware Basin adjacent to our Reeves County holdings in Texas, and an additional 100,000 net acres in other areas of the United States. In addition, upon closing of the acquisition, approximately 64,000 net acres in Reeves County, Texas were dedicated to Noble Midstream Partners for infield crude oil, natural gas and produced water gathering.
In connection with the acquisition, we incurred acquisition-related costs of $100 million, including $64 million of severance, consulting, investment, advisory, legal and other merger-related fees and $36 million of noncash share-based compensation expense, all of which were expensed and are included in other operating expense, net in our consolidated statements of operations. In addition, we received approximately 720,000 shares
The transaction was accounted for as a business combination using the acquisition method. The allocation of common stock fromthe total purchase price of Clayton Williams Energy shareholders forto the payment of withholding taxes dueassets acquired and the liabilities assumed was based on the vesting of their restricted stock and options pursuant tofair values at the purchase and sale agreement, resulting in a $25 million increase in our treasury stock balance.
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| Notes to Consolidated Financial Statements | |
Purchase Price Allocation The transaction was accounted for as a business combination using the acquisition method. The following table represents the allocation of the total purchase price of Clayton Williams Energy to the assets acquired and the liabilities assumed based on the fair value at the acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill.
The following table sets forth our purchase price allocation: |
| | | |
| (millions, except per share amounts) | |
| Fair Value of Common Stock Issued | $ | 1,851 |
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| Plus: Cash Consideration Paid to Clayton Williams Energy Stockholders | 637 |
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| Total Purchase Price | $ | 2,488 |
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| Plus Liabilities Assumed by Noble Energy: | |
| Accounts Payable | 99 |
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| Other Current Liabilities | 38 |
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| Long-Term Deferred Tax Liability | 515 |
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| Long-Term Debt | 595 |
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| Asset Retirement Obligations | 63 |
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| Total Purchase Price Plus Liabilities Assumed | $ | 3,798 |
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The fair values$1.3 billion of Clayton Williams Energy's identifiable assets aregoodwill recorded as follows: |
| | | |
| (millions) | |
| Cash and Cash Equivalents | $ | 21 |
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| Other Current Assets | 70 |
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| Oil and Gas Properties: | |
| Proved Reserves | 722 |
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| Undeveloped Leasehold Cost | 1,571 |
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| Gathering and Processing Assets | 48 |
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| Asset Retirement Costs | 63 |
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| Other Property Plant and Equipment | 12 |
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Implied Goodwill (1) | 1,291 |
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| Total Asset Value | $ | 3,798 |
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(1) The goodwill, which was associated withpart of the Texas reporting unit included within our oil and gas exploration and production segment,transaction was fully impaired as of December 31,in fourth quarter 2018. See Note 6. Goodwill Impairment.In connection with the acquisition, we assumed, and then subsequently retired, all of Clayton Williams Energy's long-term debt at a cost to us of $595 million. The fair value measurements of long-term debt were estimated based on the early redemption prices and represent Level 1 inputs.
The fair value measurements of crude oil and natural gas properties and AROs are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and AROs were measured using valuation techniques that convert expected future cash flows to a single discounted amount. Significant inputs to the valuation of crude oil and natural gas properties included estimates of: (i) proved, possible and probable reserves; (ii) production rates and related development timing; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average cost of capital rate. These inputs required significant judgments and estimates by management at the time of the valuation and are the most sensitive and may be subject to change.
Results of Operations The results of operations attributable to Clayton Williams Energy are included in our consolidated statements of operations beginning on April 24, 2017. We generated revenuesfor 2019 and 2018. Revenues of $99 million and a pre-tax net loss of $19 million were generated from the Clayton Williams Energy assets during the period April 24, 2017 to December 31, 2017.
Pro Forma Financial InformationThe following pro forma condensed combined financial information was derived from the historical financial statements of Noble Energy and Clayton Williams Energy and gives effect to the acquisition as if it had occurred on January 1, 2016. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including (i) Noble Energy's common stock and equity awards issued to convert Clayton Williams Energy's outstanding shares of common stock and equity awards and conversion of warrants as of the closing date of the acquisition, (ii) depletion of Clayton Williams Energy's fair-valued proved crude oil and natural gas properties, and (iii) the estimated tax impacts of the pro forma adjustments.
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| Notes to Consolidated Financial Statements | |
Additionally, pro forma earnings for the year ended December 31, 2017 were adjusted to exclude acquisition-related costs of $100 million incurred by Noble Energy and $23 million incurred by Clayton Williams Energy. The pro forma results of operations do not include any cost savings or other synergies that we expect to realize from the Clayton Williams Energy Acquisition or any estimated costs that have been or will be incurred by us to integrate the Clayton Williams Energy assets. The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Clayton Williams Energy Acquisition taken place on January 1, 2016; furthermore, the financial information is not intended to be a projection of future results. |
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| | Year Ended December 31, |
| (millions, except per share amounts) | 2018 (1) | | 2017 | | 2016 |
| Revenues | $ | 4,986 |
| | $ | 4,304 |
| | $ | 3,651 |
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| Net Income (Loss) and Comprehensive Income (Loss) Attributable to Noble Energy | (66 | ) | | (678 | ) | | (1,082 | ) |
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| Net Income (Loss) Attributable to Noble Energy per Common Share | | | | | |
| Basic | $ | (0.14 | ) | | $ | (1.39 | ) | | $ | (2.23 | ) |
| Diluted | $ | (0.14 | ) | | $ | (1.39 | ) | | $ | (2.23 | ) |
(1)No pro forma adjustments were made for the period as Clayton Williams Energy operations are included in our historical results.
Marcellus Shale Upstream DivestitureOn June 28,In 2017, we closed the sale ofsold all of our Marcellus Shale upstream assets, which were primarily natural gas properties. The sales price totaled $1.2 billion, and we received $1.0 billion of net cash proceeds, after consideration of customary closing adjustments. The sales price includes additional contingent consideration of up to $100 million structured as three3 separate payments of $33.3 million each. The contingent payments are in effecteach for each annual period through 2020, should the average annual price of the Appalachia Dominion, South Point index exceed $3.30 per MMBtu in the individual annual periods from 2018 through 2020. Nocertain conditions be met. NaN amounts have been accrued related to the contingent consideration. Proceeds from the transaction were used to repay borrowings resulting from the Clayton Williams Energy Acquisition. See Note 9. Long-Term Debt. For the year ended December 31, 2017, weWe recognized a loss on divestiture of $2.3 billion, or $1.5 billion after-tax.after-tax, and recorded exit costs for retained financial commitments of $93 million, discounted. The aggregate net book value of the properties sold was approximately $3.4 billion, which included approximately $883 million of undeveloped leasehold cost.
After the property sale, we retained certain firm transportation commitments to flow Marcellus Shale natural gas production. See Note 10. Marcellus Shale Firm11. Exit Cost – Transportation Commitments. Other US Onshore Transactions We conducted the following additional transactions in 2017:
receivedsold certain US onshore properties receiving total proceeds of $671 million, resulting from the sale of certain US onshore properties, including $568 million related to divestment of non-core acreage in the DJ Basin. Proceeds were applied to reduce field basis with no recognition of gain or loss.
received $335 million and recognized a gain of $334 million on the sale of mineral and royalty assets covering approximately 140,000 net mineral acres concentrated primarily in Texas, Oklahoma and North Dakota.
completed the acquisition ofacquired Delaware Basin properties, including seven7 producing wells, increasing our contiguous acreage position in the Reeves County, Texas area. Consideration totaled $301 million, approximately $246 million of which was allocated to undeveloped leasehold cost.
Asset Sale to Noble Midstream PartnersIn June 2017, we sold interests in certain midstream assets to Noble Midstream Partners Asset Contribution On June 26, 2017, Noble Midstream Partners acquired an additional 15% limited partner interest in Blanco River DevCo LP (Blanco River DevCo), increasing its ownership to 40% of the Blanco River DevCo LP, and acquired the remaining 20% limited partner interest in Colorado River DevCo LP (Colorado River DevCo) from us for $270 million.
Blanco River DevCo holds Noble Midstream Partners’ Delaware Basin in-field gathering dedications for crude oil and produced water gathering services on approximately 111,000 net acres, with substantially all of the acreage also dedicated for natural gas gathering. Colorado River DevCo provides services across our development areas in the DJ Basin, including crude oil and natural gas gathering and water services in the Wells Ranch area and crude oil gathering in the East Pony area.
The $270 million, considerationwhich consisted of $245 million in cash and 562,430 common units representing limited partner interests in Noble Midstream Partners.Partners common units. Noble Midstream Partners funded the cash consideration with approximately $138 million of net proceeds from a concurrent private placement of common units, $90 million of borrowings under the Noble Midstream Services Revolving Credit Facility and the remainder from cash on hand.
Note 5. Equity Method Investments
The carrying values of our equity method investments, including the respective segments, are as follows: |
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| | | | | | December 31, |
| (millions, except percentages) | Segment | | Ownership | | 2019 | | 2018 |
| Eastern Mediterranean Pipeline B.V. | Eastern Mediterranean | | 25% | | $ | 189 |
| | $ | — |
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Atlantic Methanol Production Company, LLC and Affiliates(1) | West Africa | | 45% | | 160 |
| | 146 |
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Alba Plant LLC (2) | West Africa | | 28% | | 56 |
| | 58 |
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| EPIC Y-Grade, LP | Midstream | | 15% | | 166 |
| | — |
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| EPIC Crude Holdings, LP | Midstream | | 30% | | 339 |
| | — |
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| Delaware Crossing LLC | Midstream | | 50% | | 69 |
| | — |
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| Advantage Pipeline, L.L.C. | Midstream | | 50% | | 77 |
| | 73 |
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| Other | N/A | | N/A | | 10 |
| | 9 |
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Total Equity Method Investments (3) | | | | | $ | 1,066 |
| | $ | 286 |
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(1) | Atlantic Methanol Production Company, LLC (AMPCO) owns and operates a methanol plant and related facilities in Equatorial Guinea. |
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(2) | Alba Plant LLC owns and operates a LPG processing plant in Equatorial Guinea. |
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| Notes to Consolidated Financial Statements | |
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(3) | At December 31, 2019, total carrying values were $42 million higher than the underlying net assets of the investments, primarily due to capitalized interest which is amortized into earnings over the useful life of the related assets. |
At December 31, 2019, consolidated retained earnings included $73 million related to the undistributed earnings of equity method investments.
Acquisitions and Divestitures
Year Ended December 31, 2019
EMED Pipeline B.V.During third quarter 2019, we acquired a 25% equity interest in Eastern Mediterranean Pipeline B.V. (EMED Pipeline B.V.). In fourth quarter 2019, EMED Pipeline B.V. acquired an approximate 39% equity interest in East Mediterranean Gas Company S.A.E. (EMG), which owns the EMG Pipeline. Upon closing of EMED Pipeline B.V.'s equity acquisition of EMG, we own an effective, indirect interest of approximately 10%, net, in EMG. The EMG Pipeline provides connection from the Israel pipeline network to Egyptian customers and supports delivery of natural gas from our producing fields offshore Israel into Egypt. During 2019, we made capital contributions of $189 million in EMED Pipeline B.V., primarily to fund the EMG equity acquisition.
EPIC Pipelines In first quarter 2019, Noble Midstream Partners exercised and closed options with EPIC Midstream Holdings, LP (EPIC) to acquire a 15% equity interest in EPIC Y-Grade, LP (EPIC Y-Grade), which constructed the EPIC Y-Grade Pipeline, and a 30% equity interest in EPIC Crude Holdings, which is constructing the EPIC Crude Oil Pipeline. The pipelines support transportation of production from the Delaware Basin to Corpus Christi, Texas. Noble Midstream Partners made capital contributions of $169 million and $351 million in EPIC Y-Grade and EPIC Crude Holdings, respectively, in 2019.
Delaware Crossing Joint VentureIn February 2019, Noble Midstream Partners formed a 50/50 joint venture with Salt Creek Midstream LLC. The joint venture, Delaware Crossing LLC, is constructing a crude oil pipeline system in the Delaware Basin. Noble Midstream Partners made capital contributions of $70 million for its share of pipeline construction costs in 2019.
Year Ended December 31, 2018
Divestiture of Marcellus Shale CONE GatheringIn January 2018, we sold our 50% interest in CONE Gathering LLC (CONE Gathering) to CNX Resources Corporation. CONE Gathering owns the general partner of CNX Midstream Partners LP (CNX Midstream Partners, NYSE: CNXM). We received proceeds of $309 million in cash and recognized a pre-tax gain of $196 million. After the sale, we held 21.7 million common units, representing a 34.1% limited partner interest, in CNX Midstream Partners. During 2018, we sold our 21.7 million common units, receiving net proceeds fromof approximately $387 million, and recognized a concurrent private placementgain of common units and $90 million of borrowings$307 million. The investment was previously accounted for under the Noble Midstream Services Revolving Credit Facility and the remainder from cash on hand.equity method of accounting.
Year Ended December 31, 2017
Noble Midstream Partners Advantage Joint VentureOnIn April 3, 2017, Noble Midstream Partners and Plains Pipeline, L.P.,acquired a wholly owned subsidiary of Plains All American Pipeline, L.P., acquired50% interest in Advantage Pipeline, L.L.C. (Advantage Pipeline) for $133 million through a newly formed 50/50 joint venture (Advantage Joint Venture). Noble Midstream Partners contributed approximately $67 million of cash to the Advantage Joint Venture, funded by available cash on hand and the Noble Midstream Services Revolving Credit Facility. The Advantage Joint Venture is accounted for under the equity method and is included within our Midstream segment. See Note 15. Equity Method Investments. Noble Midstream Partners serves as operator of themillion. Advantage Pipeline System, which includesowns a 70-mile crude oil pipeline system in the southern Delaware Basin from Reeves County, Texas to Crane County, Texas, with 150 MBbls per day of shipping capacity and 490 MBbls of storage capacity.
Other Acquisitions and Divestitures During 2017,for which we closed on the acquisition of other smaller US onshore properties for total cash consideration of $26 million. We also closed the sale of certain other smaller US onshore and international properties and received total cash consideration of $39 million, recording a loss of $6 million.
Year Ended December 31, 2016
Termination of Marcellus Shale JDA In fourth quarter 2016, we and CONSOL Energy Inc. (CONSOL) agreed to terminate our 50-50 Joint Development Agreement (JDA) in the Marcellus Shale. In connection with the terminated JDA, we executed and closed an exchange agreement whereby we and CONSOL each transferred all of our interest in a portion of co-owned properties to one another. In addition to the acreage and production realignment between the two companies, we remitted a cash payment of approximately $213 million to CONSOL at closing. Terminating the JDA resulted in the elimination of the remaining outstanding carried cost obligation due from us. No gain or loss was recognized on the exchange.serve as operator.
DJ Basin Acreage Exchange We closed a cashless acreage exchange in the DJ Basin receiving approximately 11,700 net acres within our Wells Ranch development area in exchange for approximately 13,500 net acres primarily from our Bronco area. No gain or loss was recognized.
2016 DivestituresDuring 2016, we engaged in the following sales transactions:
entered an agreement to divest certain producing and non-producing properties covering approximately 33,100 net acres in the DJ Basin for proceeds of $505 million. We closed the sale on a portion of the properties in 2016, receiving proceeds of $486 million, with the remainder of the sale closing in 2017. Proceeds were applied to reduce field basis with no recognition of gain or loss;
sold additional DJ Basin non-producing properties, certain Eagle Ford properties, our Bowdoin property in northern Montana, and certain other smaller US onshore properties, generating total net proceeds of $152 million, a net loss of $23 million on the Bowdoin sale, and no further gain or loss recognized on the remaining transactions;
sold our 47% interest in the Alon A and Alon C licenses, which included the Karish and Tanin fields, offshore Israel, for a total sales price of $73 million ($67 million for asset consideration and $6 million from cost adjustments). Proceeds were applied to reduce field basis with no recognition of gain or loss;
sold a 3.5% working interest in the Tamar and Dalit fields, offshore Israel, in compliance with the terms of the Framework, which requires us to reduce our ownership interest in the fields to 25% by year-end 2021. The sales price totaled $431 million, and we received net cash proceeds of $316 million, after consideration of timing and tax adjustments, at closing. Proceeds were ratably applied to the fields basis and resulted in the recognition of a $261 million gain; and
received proceeds of $131 million related to the farm-out of a 35% interest in Block 12, which includes the Aphrodite natural gas discovery, offshore Cyprus. We received the remaining proceeds of $40 million in January 2017. Proceeds were applied to reduce field basis with no recognition of gain or loss.
Other Divestitures During 2016, we also closed the sale of certain smaller US onshore properties and received total cash consideration of $83 million, with no recognition of gain or loss.
Note 6. Goodwill Impairment
As of December 31, 2017 and through September 30, 2018, our consolidatedSummarized, 100% combined balance sheet included goodwill of $1.4 billion, of which $1.3 billion, resulting from the Clayton Williams Energy Acquisition,information for equity method investments was allocated to our Texas reporting unit, includedas follows: |
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| | December 31, |
| (millions) | 2019 | | 2018 |
| Current Assets | $ | 681 |
| | $ | 387 |
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| Noncurrent Assets | 5,306 |
| | 575 |
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| Current Liabilities | 607 |
| | 198 |
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| Noncurrent Liabilities | 2,243 |
| | 81 |
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| Notes to Consolidated Financial Statements | |
within our oil and gas exploration and production segment, and $110 million was allocated to our Midstream reporting unit. We conducted our annual goodwill impairment assessment as of September 30, 2018. At that time, we concluded that goodwill was not impaired.
In fourth quarter 2018, we considered changes to facts and circumstances, particularly the decline in WTI strip pricing, increase in operating and capital costs, as well as our development plan, and concluded that it was more likely than not that the fair value of our Texas reporting unit was less than its carrying amount. For purposes of determining the goodwill impairment, we estimated the implied fair value of the goodwill using a variety of valuation methods, including the income and market approaches. Our estimate of fair value required us to use significant unobservable inputs, representative of a Level 3 fair value measurement, including assumptions for future crude oil and natural gas production, commodity prices based on forward commodity price curves, operating and development costs and other factors. The analysis indicated that the implied fair value of our Texas reporting unit goodwill was zero and we recognized a loss of $1.3 billion.
Note 7. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs
Capitalized Exploratory Well Costs We capitalize exploratory well costs until a determination is made that the well has found proved reserves or is deemed noncommercial. On a quarterly basis, we review the status of suspended exploratory well costs and assess the development of these projects. If a well is deemed to be noncommercial, the well costs are charged to exploration expense as dry hole cost.
Changes in capitalized exploratory well costs, excluding amounts that were capitalized and subsequently expensed in the same period, are as follows: |
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| | Year Ended December 31, |
| (millions) | 2018 | | 2017 | | 2016 |
| Capitalized Exploratory Well Costs, Beginning of Period | $ | 520 |
| | $ | 768 |
| | $ | 1,353 |
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| Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves | 7 |
| | 20 |
| | 84 |
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Divestitures and Other (1) | (168 | ) | | — |
| | (143 | ) |
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves or to Assets Held for Sale (2) | (1 | ) | | (203 | ) | | (1 | ) |
Capitalized Exploratory Well Costs Charged to Expense (3) | (4 | ) | | (65 | ) | | (525 | ) |
| Capitalized Exploratory Well Costs, End of Period | $ | 354 |
| | $ | 520 |
| | $ | 768 |
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(1) The 2018 amount represents costs primarily related to Gulf of Mexico assets sold during second quarter and the 2016 amount relates to the farm-down of a 35% interest in Block 12 offshore Cyprus to a new partner.
(2) The 2017 amount relates to the approval and sanction of the first phase of development of the Leviathan field.
(3) Capitalized exploratory well costs charged to expense are included within exploration or impairment expense in our consolidated statements of operations. The 2017 amount relates primarily to the write-off of costs associated with the Troubadour natural gas discovery, Gulf of Mexico, for which we chose not to pursue development activities. The 2016 amount relates primarily to discoveries offshore West Africa. Following review of additional 3D seismic data, we determined these discoveries were impaired in the current forward outlook for crude oil prices. We also incurred expenses associated with the Silvergate exploratory well, Gulf of Mexico, which did not encounter commercial hydrocarbons and was subsequently plugged and abandoned.
The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced: |
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| | December 31, |
| (millions) | 2018 | | 2017 | | 2016 |
| Exploratory Well Costs Capitalized for a Period of One Year or Less | $ | 6 |
| | $ | 10 |
| | $ | 69 |
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| Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 348 |
| | 510 |
| | 699 |
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| Balance at End of Period | $ | 354 |
| | $ | 520 |
| | $ | 768 |
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| Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 7 |
| | 8 |
| | 10 |
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| Notes to Consolidated Financial Statements | |
The following table provides a further agingSummarized, 100% combined statements of those exploratory well costs that have been capitalizedoperations for a period greater than one year since the commencement of drillingequity method investments was as of December 31, 2018:follows: |
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| | | | Suspended Since | | |
Country/Project (millions) | Total | | 2016 - 2017 | | 2014 - 2015 | | 2013 & Prior | | Progress |
| Offshore Equatorial Guinea | | | | | | | | | |
| Felicita (Block O) | $ | 48 |
| | $ | 3 |
| | $ | 7 |
| | $ | 38 |
| | We are in process of evaluating regional development scenarios for this 2008 natural gas discovery. In early 2016, we began analyzing, interpreting and evaluating the acquired seismic data. In 2018, we progressed definitive agreements to sell natural gas through the Punta Europa plants, which will expand the options for additional natural gas sales. |
| Yolanda (Block I) | 24 |
| | 2 |
| | 3 |
| | 19 |
| | A data exchange agreement for the 2007 Yolanda condensate and natural gas discovery has been executed between the governments of Equatorial Guinea and Cameroon. Our development team is working with both governments to evaluate natural gas monetization options for both Yolanda and YoYo (Cameroon) discoveries. In 2018, we progressed the definitive agreements to sell natural gas through the Punta Europa plants, which will open the options for additional natural gas sales. |
| Offshore Cameroon | |
| | |
| | |
| | |
| | |
| YoYo (YoYo Block) | 52 |
| | (1 | ) | | 6 |
| | 47 |
| | A data exchange agreement for the 2007 YoYo condensate and natural gas discovery has been executed between the governments of Equatorial Guinea and Cameroon. Our development team is working with both governments to evaluate natural gas monetization options for both Yolanda (Equatorial Guinea) and YoYo discoveries. In June 2017, we converted our mining concession license for the YoYo block into a PSC. In 2018, we progressed the definitive agreements to sell natural gas through the Punta Europa plants, which will open the options for additional natural gas sales. |
| Offshore Israel | |
| | |
| | |
| | |
| | |
| Leviathan-1 Deep | 94 |
| | 6 |
| | 8 |
| | 80 |
| | The well did not reach the target interval in 2012. In 2018, we continued to reprocess and review seismic information for this prospect, incorporating information obtained from other recent discoveries in the region and developing future drilling plans to test this deep oil concept, which is held by the Leviathan Development and Production Leases. |
| Dalit | 24 |
| | 2 |
| | 3 |
| | 19 |
| | Our future development plan was approved by the Government of Israel to develop this 2009 natural gas discovery with a tie-in to existing infrastructure at Tamar. Currently, we are analyzing 3D seismic data to evaluate additional potential of the area. |
| Offshore Cyprus | | | | | | | | | |
| Cyprus | 100 |
| | 11 |
| | 12 |
| | 77 |
| | We continue to work with the Government of Cyprus to obtain approval of our development plan and the issuance of an Exploitation License. During 2017, we submitted an updated development plan. During 2018, we continued to progress capital project cost improvement and regional natural gas marketing efforts. |
| Other | |
| | |
| | |
| | |
| | |
| Projects less than $20 million | 6 |
| | (7 | ) | | 10 |
| | 3 |
| | Continuing to assess and evaluate wells. |
| Total | $ | 348 |
| | $ | 16 |
| | $ | 49 |
| | $ | 283 |
| | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| (millions) | 2019 | | 2018 | | 2017 |
| Operating Revenues | $ | 1,018 |
| | $ | 855 |
| | $ | 790 |
|
| Operating Expenses | 853 |
| | 284 |
| | 303 |
|
| Operating Income | 165 |
| | 571 |
| | 487 |
|
| Other (Loss) Income, net | (33 | ) | | 3 |
| | 15 |
|
| Income Before Income Taxes | 132 |
| | 574 |
| | 502 |
|
| Income Tax Provision | 72 |
| | 152 |
| | 136 |
|
| Net Income | $ | 60 |
| | $ | 422 |
| | $ | 366 |
|
Undeveloped Leasehold Costs Undeveloped leasehold costs are derived from allocated fair values as a result of business combinations or other purchases of unproved properties and are subject to impairment testing. We reclassify undeveloped leasehold costs to proved property costs when, as a result of exploration and development activities, probable and possible resources are reclassified to proved reserves, including proved undeveloped reserves. On the other hand, if, based upon a
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
change in exploration plans, timing and extent of development activities, availability of capital and suitable rig and drilling equipment, resource potential, comparative economics, changing regulations and/or other factors, an impairment is indicated, we record impairment expense related to the respective leases or licenses.
Changes in undeveloped leasehold costs were as follows: |
| | | | | | | |
| | December 31, |
| (millions) | 2018 | | 2017 |
| Undeveloped Leasehold Costs, Beginning of Period | $ | 2,922 |
| | $ | 2,197 |
|
Additions to Undeveloped Leasehold Costs (1) | 47 |
| | 1,859 |
|
Transfers to Proved Properties (2) | (453 | ) | | (174 | ) |
Assets Sold (3) | (142 | ) | | (884 | ) |
Impairment (4) | (1 | ) | | (62 | ) |
| Other | — |
| | (14 | ) |
| Undeveloped Leasehold Costs, Net of Impairment, End of Period | $ | 2,373 |
| | $ | 2,922 |
|
| |
(1)
| 2017 additions relate to the Clayton Williams Energy Acquisition and Delaware Basin asset acquisition. |
| |
(2)
| 2018 transfers relate primarily to Delaware Basin assets. |
| |
(3)
| 2017 sales relate primarily to the Marcellus Shale upstream divestiture. |
| |
(4)
| 2017 impairment expense was primarily attributable to Gulf of Mexico leases. |
As of December 31, 2018, remaining undeveloped leasehold costs, to which proved reserves had not been attributed, totaled $2.4 billion, including $2.2 billion and $100 million attributable to Delaware Basin and Eagle Ford Shale, respectively.
The remaining balance of undeveloped leasehold costs as of December 31, 2018 included $53 million and $31 million related to international and domestic unproved properties, respectively. These costs pertain to acquired leases or licenses that are subject to expiration over the next several years unless production is established on units containing the acreage. These costs are evaluated as part of our periodic impairment review.
Note 8.6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs
Capitalized Exploratory Well CostsWe capitalize exploratory well costs until a determination is made that the well has found proved reserves or is deemed noncommercial. These costs are included in Oil and Gas Properties on our consolidated balance sheets. On a quarterly basis, we review the status of suspended exploratory well costs and assess the development of these projects. If a well is deemed to be noncommercial, the well costs are charged to exploration expense as dry hole cost.
Changes in capitalized exploratory well costs, excluding amounts that were capitalized and subsequently expensed in the same period, are as follows: |
| | | | | | | | | | | |
| | Year Ended December 31, |
| (millions) | 2019 | | 2018 | | 2017 |
| Capitalized Exploratory Well Costs, Beginning of Period | $ | 354 |
| | $ | 520 |
| | $ | 768 |
|
| Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves | 26 |
| | 7 |
| | 20 |
|
Divestitures (1) | — |
| | (168 | ) | | — |
|
Reclassified to Proved Oil and Gas Properties, Based on Determination of Proved Reserves, or to Assets Held for Sale (2) | — |
| | (1 | ) | | (203 | ) |
Capitalized Exploratory Well Costs Charged to Expense (3) | (100 | ) | | (4 | ) | | (65 | ) |
| Capitalized Exploratory Well Costs, End of Period | $ | 280 |
| | $ | 354 |
| | $ | 520 |
|
| |
(1) | The 2018 amount relates to the second quarter 2018 sale of our Gulf of Mexico assets. |
| |
(2) | The 2017 amount relates to the approval and sanction of the first phase of development of the Leviathan field. |
| |
(3) | In fourth quarter 2019, we recorded exploration expense of $100 million related to the Leviathan Deep prospect, offshore Israel, which was initially drilled in 2012 but did not reach the target interval. Throughout this time, we have evaluated seismic information and nearby discoveries in the region. Upon concluding we would not move forward with the project, we wrote off the entire amount of capitalized exploratory well costs associated with this prospect. The 2017 amount relates to a write-off of costs for a natural gas discovery in the Gulf of Mexico. See Note 10. Impairments. |
The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced: |
| | | | | | | | | | | |
| | December 31, |
| (millions, except number of projects) | 2019 | | 2018 | | 2017 |
| Exploratory Well Costs Capitalized for a Period of One Year or Less | $ | 22 |
| | $ | 6 |
| | $ | 10 |
|
| Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 258 |
| | 348 |
| | 510 |
|
| Balance at End of Period | $ | 280 |
| | $ | 354 |
| | $ | 520 |
|
| Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 5 |
| | 7 |
| | 8 |
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| 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, 2019: |
| | | | | | | | | | | | | | | | | |
| | | | Suspended Since | | |
| (millions) | Total | | 2017 - 2018 | | 2015 - 2016 | | 2014 & Prior | | Progress |
| Offshore Eastern Mediterranean | | | | | | | | |
| Dalit (Offshore Israel) | $ | 23 |
| | $ | (9 | ) | | $ | 3 |
| | $ | 29 |
| | Our future development plan for this 2008 natural gas discovery, consisting of a tie-in to existing infrastructure at Tamar, was approved by the Government of Israel in 2019. During 2019, we continued analyzing 3D seismic data to evaluate additional potential of the area. |
| Cyprus (Offshore Cyprus) | 100 |
| | 3 |
| | 15 |
| | 82 |
| | During 2019, we received approval of our Plan of Development and Exploitation License from the Government of Cyprus. We continued to progress capital project cost improvement and regional natural gas marketing efforts. |
| Offshore West Africa | | | | | | | | | |
| Felicita (Block O, Offshore Equatorial Guinea) | 49 |
| | 2 |
| | 4 |
| | 43 |
| | We are in the process of evaluating regional development scenarios for this 2008 natural gas discovery. The recent sanction of the Alen Gas Monetization project, which represents the initial step in establishing a regional natural gas hub, expands the options for development of this discovery through existing infrastructure. |
| YoYo (YoYo Block, Offshore Cameroon) and Yolanda (Block I, Offshore Equatorial Guinea) | 80 |
| | 2 |
| | 5 |
| | 73 |
| | A data exchange agreement for these 2007 condensate and natural gas discoveries has been executed between the governments of Equatorial Guinea and Cameroon. Our development team is working with both governments to evaluate natural gas monetization options. The recent sanction of the Alen Gas Monetization project, which represents the initial step in establishing a regional natural gas hub, expands the options for development of this discovery through existing infrastructure. |
| Other | |
| | |
| | |
| | |
| | |
| Projects less than $20 million | 6 |
| | (1 | ) | | (10 | ) | | 17 |
| | Continuing to assess and evaluate wells. |
| Total | $ | 258 |
| | $ | (3 | ) | | $ | 17 |
| | $ | 244 |
| | |
Undeveloped Leasehold Costs Changes in undeveloped leasehold costs, which are recorded in oil and gas properties on our consolidated balance sheets, were as follows: |
| | | | | | | |
| | Year Ended December 31, |
| (millions) | 2019 | | 2018 |
| Undeveloped Leasehold Costs, Beginning of Period | $ | 2,373 |
| | $ | 2,922 |
|
| Additions to Undeveloped Leasehold Costs | 59 |
| | 47 |
|
Transfers to Proved Properties (1) | (184 | ) | | (453 | ) |
Assets Sold (2) | (96 | ) | | (142 | ) |
| Impairment | — |
| | (1 | ) |
| Undeveloped Leasehold Costs, End of Period | $ | 2,152 |
| | $ | 2,373 |
|
| |
(1) | Transfers primarily relate to development of Delaware Basin assets. |
| |
(2) | Amounts primarily relate to Delaware Basin assets sold. See Note 4. Acquisitions and Divestitures. |
As of December 31, 2019, undeveloped leasehold costs included $1.9 billion, $100 million, $79 million, and $58 million attributable to the Delaware Basin, Eagle Ford Shale, other US onshore properties, and international properties, respectively. Certain of these costs pertain to acquired leases or licenses that are subject to expiration over the next several years unless production is established on units containing the acreage. Other costs pertain to acreage that is being held by production.
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| Notes to Consolidated Financial Statements | |
Note 7. Asset Retirement Obligations
AROAsset retirement obligations (ARO) consists primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Changes in ARO are as follows: | | | | Year Ended December 31, | Year Ended December 31, |
| (millions) | 2018 | | 2017 | 2019 | | 2018 |
| Asset Retirement Obligations, Beginning Balance | $ | 875 |
| | $ | 935 |
| |
| Asset Retirement Obligations, Beginning of Period | | $ | 880 |
| | $ | 875 |
|
| Liabilities Incurred | 25 |
| | 94 |
| 70 |
| | 25 |
|
| Liabilities Settled | (345 | ) | | (82 | ) | (110 | ) | | (345 | ) |
| Revisions of Estimates | 293 |
| | (65 | ) | (69 | ) | | 293 |
|
| Reclassification to Liabilities Associated with Assets Held for Sale | (1 | ) | | (54 | ) | — |
| | (1 | ) |
| Accretion Expense | 33 |
| | 47 |
| 43 |
| | 33 |
|
| Asset Retirement Obligations, Ending Balance | $ | 880 |
| | $ | 875 |
| |
| Asset Retirement Obligations, End of Period | | $ | 814 |
| | $ | 880 |
|
Year Ended December 31, 2019Liabilitiesincurred included $43 million in Israel, primarily related to costs associated with the Leviathan field, and $20 million in US onshore, primarily related to the DJ and Delaware Basins.The majority of liabilities settled relate to abandonment of properties in the DJ Basin where we have engaged in a program to plug and abandon older vertical wells. Costs associated with these abandonment activities will be incurred over several years. Revisions of estimates include a decrease of $72 million in the DJ Basin as a result of improved cycle times and cost reductions for vertical wells.
Year Ended December 31, 2018 Liabilities settled primarily included $216 million and $24 million of liabilities assumed by the purchasers of the Gulf of Mexico properties and Greeley Crescent assets, respectively, and $104 million related to abandonment of US onshore properties, primarily in the DJ Basin, where we have engaged in a program to plug and abandon older vertical wells. Costs associated with the DJ Basin abandonment activities will be incurred over several years.wells, as discussed above.
Revisions of estimates were primarily related to increases in cost estimates and changes in timing estimates of $287 million for US onshore, primarily in the DJ Basin related to the abandonment activities noted above, $10 million for wells offshore Israel and $9 million for wells offshore Equatorial Guinea, partially offset by decreases in cost and timing estimates of $17 million associated with the North Sea abandonment project.
Year Ended December 31, 2017 Liabilities incurred include $63 million related to the Clayton Williams Energy Acquisition and $31 million primarily for other US onshore wells and midstream facilities placed into service.
Liabilities settled include $43 million related to abandonment of US onshore properties, $19 million related to properties sold in the Greeley Crescent (DJ Basin) acreage divestiture, $12 million related to properties sold in the Marcellus Shale upstream divestiture and $8 million related to other offshore domestic and international properties.
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Revisions of estimates include a $42 million decrease related to changes in cost and timing associated with the North Sea abandonment project and a $38 decrease for US onshore and Gulf of Mexico properties, partially offset by an increase of $15 million for West Africa.
In 2017, we also transferred $42 million and $12 million of ARO liabilities associated with Southwest Royalties and Tamar field, respectively, to liabilities associated with assets held for sale. See Note 5. Acquisitions and Divestitures.Note 9.8. Long-Term Debt
Our debt consists of the following: | | | | December 31, 2018 | | December 31, 2017 | December 31, 2019 | | December 31, 2018 |
| (millions, except percentages) | Debt | | Interest Rate | | Debt | | Interest Rate | Debt | | Interest Rate | | Debt | | Interest Rate |
| Noble Energy, Excluding Noble Midstream Partners | | | | | | | | |
| Revolving Credit Facility, due March 9, 2023 | $ | — |
| | — | % | | $ | 230 |
| | 2.27 | % | $ | — |
| | — | % | | $ | — |
| | — | % |
| Noble Midstream Services Revolving Credit Facility, due March 9, 2023 | 60 |
| | 3.67 | % | | 85 |
| | 2.75 | % | |
| Noble Midstream Services Term Loan Credit Facility, due July 31, 2021 | 500 |
| | 3.42 | % | | — |
| | — | % | |
Senior Notes, due May 1, 2021 (1) | — |
| | — | % | | 379 |
| | 5.63 | % | |
| Commercial Paper Borrowings | | — |
| | — | % | | — |
| | — | % |
| Senior Notes, due December 15, 2021 | 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 October 15, 2029 | | 500 |
| | 3.25 | % | | — |
| | — | % |
| 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 | % | |
| Capital Lease Obligations | 223 |
| | — | % | | 273 |
| | — | % | |
| Total | $ | 6,675 |
| | |
| | $ | 6,859 |
| | |
| |
| Unamortized Discount | (22 | ) | | |
| | (24 | ) | | |
| |
Unamortized Premium (1) | — |
| | | | 12 |
| | | |
| Unamortized Debt Issuance Costs | (38 | ) | | | | (40 | ) | | | |
| Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs | $ | 6,615 |
| | |
| | $ | 6,807 |
| | |
| |
| Senior Notes, due October 15, 2049 | | 500 |
| | 4.20 | % | | — |
| | — | % |
| Senior Debentures | | 84 |
| | 7.25 | % | | 92 |
| | 7.13 | % |
| Finance Lease Obligations | | 205 |
| | — | % | | 223 |
| | — | % |
| Total Noble Energy Debt, Excluding Noble Midstream Partners Debt | | 6,089 |
| | | | 6,115 |
| | |
| Noble Midstream Partners | | | | | | | | |
| Noble Midstream Services Revolving Credit Facility, due March 9, 2023 | | 595 |
| | 3.11 | % | | 60 |
| | 3.67 | % |
| Noble Midstream Services Term Loan Credit Facility, due July 31, 2021 | | 500 |
| | 2.85 | % | | 500 |
| | 3.42 | % |
| Noble Midstream Services Term Loan Credit Facility, due August 23, 2022 | | 400 |
| | 2.74 | % | | — |
| | — | % |
| Total Noble Midstream Partners Debt | | 1,495 |
| | | | 560 |
| | |
| Total Debt | | 7,584 |
| | | | 6,675 |
| | |
| Net Unamortized Discounts and Debt Issuance Costs | | (65 | ) | | | | (60 | ) | | |
| Total Debt, Net of Unamortized Discounts and Debt Issuance Costs | | $ | 7,519 |
| | |
| | $ | 6,615 |
| | |
|
| Less Amounts Due Within One Year: | |
| | |
| | |
| | |
| | | |
| | | | |
|
| Capital Lease Obligations | (41 | ) | | |
| | (61 | ) | | |
| |
| Finance Lease Obligations | | (42 | ) | | |
| | (41 | ) | | |
|
| Long-Term Debt Due After One Year | $ | 6,574 |
| | |
| | $ | 6,746 |
| | |
| $ | 7,477 |
| | |
| | $ | 6,574 |
| | |
|
| |
(1)
| In second quarter 2018, we redeemed all of the Senior Notes due May 1, 2021, and expensed the associated premium. See Redemption of Notes, below.
|
| |
(2)
| Includes $8 million of 5.875% Senior Notes due June 1, 2024 and $84 million of 7.25% Senior Debentures due August 1, 2097. |
All of our long-term debt is senior unsecured debt and is, therefore, pari passu with respect to the payment of both principal and interest. The indenture documents of each of our notes provide that we may prepay the instruments by creating a defeasance trust. The defeasance provisions require that the trust be funded with securities sufficient, in the opinion of a nationally recognized accounting firm, to pay all scheduled principal and interest due under the respective agreements. Interest on each of these issues is payable semi-annually.
Revolving Credit Facility Our Credit Agreement, as amended, provides for a $4.0 billion unsecured revolving credit facility (Revolving Credit Facility), which is available for general corporate purposes. The Revolving Credit Facility (i) provides for facility fee rates that range from 10 basis points to 25 basis points per year depending upon our credit rating, (ii) provides for interest rates that are based upon the Eurodollar rate plus a margin that ranges from 90 basis points to 150 basis points depending upon our credit rating, and (iii) includes sub-facilities for short-term loans and letters of credit up to an aggregate amount of $500 million under each sub-facility. As of December 31, 2019, we were in compliance with our debt covenants and no amounts were outstanding under our Revolving Credit Facility.
Commercial Paper ProgramOur commercial paper program provides for short-term funding needs. The program allows Noble Energy to issue a maximum of $4.0 billion of unsecured commercial paper notes and is supported by Noble Energy’s $4.0 billion Revolving Credit Facility. Our commercial paper notes, which generally have a maturity of less than 30 days, are sold under customary terms in the commercial paper market and are generally issued at a discounted price relative to the principal face value. Such discount prices are dependent on market conditions and ratings assigned to the commercial paper program by credit rating agencies at the time of commercial paper issuance. As of December 31, 2019, we had no outstanding commercial paper borrowings.
Senior Notes Issuance and Completed Tender OfferOn October 1, 2019, we issued $500 million of 3.25% senior notes due
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
The Revolving Credit Facility requires that our total debt to capitalization ratio (as defined inOctober 15, 2029 and $500 million of 4.20% senior notes due October 15, 2049. Interest on the Revolving Credit Facility), expressed as a percentage, not exceed 65%notes is payable semi-annually beginning April 15, 2020. We may redeem some or all of the notes at any time. A violation of this covenant could result in a default undertime at the Credit Agreement, which would permitapplicable redemption price, plus accrued interest, if any. Proceeds from the participating banks to restrict our ability to access the Revolving Credit Facility and require the immediate repayment of any outstanding advances under the Revolving Credit Facility. We were in compliance with our debt covenants as of December 31, 2018.
Certain lenders that are a party to the Revolving Credit Facility have in the past performed, and may in the future from time to time perform, investment banking, financial advisory, lending or commercial banking services for us for which they have received, and may in the future receive, customary compensation and reimbursement of expenses.
In the first quarter 2018, we extended the maturity dateissuance of the Revolving Credit Facility from August 2020notes were used to March 2023. Asfund the tender offer and redemption of our $1.0 billion 4.15% notes due December 31, 2018, no borrowings were outstanding under15, 2021. In connection with the Revolving Credit Facility.tender and redemption, in fourth quarter 2019, we recorded early debt extinguishment cost of approximately $44 million in our consolidated statements of operations.
Noble Midstream Services Revolving Credit Facility Noble Midstream Services LLC (Noble Midstream Services), a subsidiary of Noble Midstream Partners, maintains a revolving credit facility (Noble Midstream Services Revolving Credit Facility), which is available to fund working capital and to finance acquisitions and other capital expenditures of Noble Midstream Partners.
Borrowings by Noble Midstream Partners In fourth quarter 2019, the capacity of the facility was increased from $800 million to almost $1.2 billion. As of December 31, 2019, $555 million was available for borrowing under the Noble Midstream Services Revolving Credit Facility bear interest at a rate equal to an applicable margin plus, at Noble Midstream Partners' option, either (a) in the case of base rate borrowings, a rate equal to the highest of (1) the prime rate, (2) the greater of the federal funds rate or the overnight bank funding rate, plus 0.5% and (3) the LIBOR for an interest period of one month plus 1.00%; or (b) in the case of LIBOR borrowings, the offered rate per annum for deposits of dollars for the applicable interest period.Facility.
The Noble Midstream Services Revolving Credit Facility includes certain financial covenants as of the end of each fiscal quarter, including a (1) consolidated leverage ratio to consolidated adjusted earnings before interest expense, income taxes, depreciation, depletion, and amortization (EBITDA) and (2) consolidated interest coverage ratio (each covenant as described in the Noble Midstream Services Revolving Credit Facility). All obligations of Noble Midstream Services, as the borrower under the Noble Midstream Services Revolving Credit Facility, are guaranteed by Noble Midstream Partners and all wholly-owned material subsidiaries of Noble Midstream Partners. Debt issuance costs associated with this facility were de minimis.
In first quarter 2018, the capacity was increased from $350 million to $800 million and the maturity date was extended from September 2021 to March 2023.
In third quarter 2018, we used $480 million proceeds from the issuance of a new term loan credit facility to repay a portion of the balance outstanding under the Noble Midstream Services Revolving Credit Facility. See was in compliance with the debt covenants for this facility as of December 31, 2019.
Noble Midstream Services 2019 Term Loan Credit Facility below. As of December 31, 2018, $60 million was outstanding under the Noble Midstream Services Revolving Credit Facility.
Noble Midstream Services Term Loan Credit Facility In third quarter 2018,On August 23, 2019, Noble Midstream Services entered into a Term Credit Agreementterm loan agreement (Noble Midstream Services 2019 Term Credit Agreement), which provides for a three yearthree-year senior unsecured term loan credit facility (Noble Midstream Servicesdue August 23, 2022 (2019 Term Loan Credit Facility) and permitswith permitted aggregate borrowings of up to $500$400 million. Proceeds from the Noble Midstream Services2019 Term Loan Credit Facility were primarily used to repay a portion of the outstanding borrowings under the Noble Midstream Services Revolving Credit Facility and to pay fees and expenses in connection with theFacility. Noble Midstream Services was in compliance with the debt covenants for this facility as of December 31, 2019.
Noble Midstream Services 2018 Term Loan Credit Facility.Facility
Borrowings under the In 2018, Noble Midstream Services entered into a term loan agreement (Noble Midstream Services 2018 Term Credit Agreement), which provides for a three-year senior unsecured term loan credit facility due July 31, 2021 (2018 Term Loan Credit Facility) with permitted aggregate borrowings of up to $500 million. Proceeds from the 2018 Term Loan Credit Facility bear interest atwere primarily used to repay a rate equal to, at Noble Midstream Partners' option, either (1) a base rate plus an applicable margin between 0.00% and 0.50% per annum or (2) a Eurodollar rate plus an applicable margin between 1.00% and 1.50% per annum. Asportion of December 31, 2018, $500 million wasthe outstanding borrowings under the Noble Midstream Services Term Loan Credit Facility.
The Noble Midstream Services Term Loan Credit Facility contains customary representations and warranties, affirmative and negative covenants, and events of default that are substantially the same as those contained in the Noble Midstream Services Revolving Credit Facility. Upon the occurrence and during the continuation of an event of default under the Noble Midstream Services Term Loanwas in compliance with the debt covenants for this facility as of December 31, 2019.
Fair Value of DebtThe fair value of fixed-rate, public debt is estimated based on the published market prices. As such, we consider the fair value of this debt to be a Level 1 measurement on the fair value hierarchy. Our non-public debt, including our Revolving Credit Facility, the lenders may declare all amounts outstanding under thecommercial paper borrowings, Noble Midstream Services Term LoanRevolving Credit Facility and Noble Midstream Services term loans are subject to variable interest rates. The fair value is estimated based on significant other observable inputs; thus, we consider the fair value to be immediately due and payable and exercise other remediesa Level 2 measurement on the fair value hierarchy. Fair value information regarding our debt is as provided by applicable law.follows: |
| | | | | | | | | | | | | | | |
| | December 31, 2019 | | December 31, 2018 |
| (millions) | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
| Debt | $ | 7,379 |
| | $ | 8,033 |
| | $ | 6,452 |
| | $ | 6,121 |
|
Redemption of Senior Notes In May 2018, we redeemed $379 million of Senior Notes due May 1, 2021 that we assumed in the merger with Rosetta Resources, Inc. in 2015 for $395 million.
Senior Notes Issuance and Completed Tender Offer Annual Debt MaturitiesOn August 15, 2017, we issued $600 millionAs of 3.85% senior unsecured notes that will mature on January 15, 2028 and $500 millionDecember 31, 2019, annual maturities of 4.95% senior unsecured notes that will mature on August 15, 2047. Interest on the 3.85% senior notes and 4.95% senior notes is payable semi-annually beginning January 15, 2018 andoutstanding debt, excluding finance lease obligations, were as follows: |
| | | | | | | | | | | |
| | Debt Principal Payments |
| (millions) | Noble Energy Excluding Noble Midstream Partners | | Noble Midstream Partners | | Total |
| 2020 | $ | — |
| | $ | — |
| | $ | — |
|
| 2021 | — |
| | 500 |
| | 500 |
|
| 2022 | — |
| | 400 |
| | 400 |
|
| 2023 | 100 |
| | 595 |
| | 695 |
|
| 2024 | 650 |
| | — |
| | 650 |
|
| Thereafter | 5,134 |
| | — |
| | 5,134 |
|
| Total | $ | 5,884 |
| | $ | 1,495 |
| | $ | 7,379 |
|
Finance Lease Obligations See Note 9. Leases.
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| Notes to Consolidated Financial Statements | |
Note 9. Leases
In the normal course of business, we enter into operating and finance lease agreements to support our operations. Operating leases primarily include office space for our corporate and field locations, US onshore compressors and drilling rigs, vessels and helicopters for offshore operations, storage facilities, and other miscellaneous assets. Finance leases include corporate office space, a trunkline in the DJ Basin, a floating production, storage and offloading vessel (FPSO) in West Africa, and vehicles. Our leasing activity is recorded and presented on a gross basis, with the exception of the FPSO which is recorded net to our interest.
Balance Sheet InformationROU assets and lease liabilities are as follows: |
| | | | |
| (millions) | Balance Sheet Location | December 31, 2019 |
| ROU Assets | | |
Operating Leases (1) | Other Noncurrent Assets | $ | 227 |
|
Finance Leases (2) | Total Property, Plant and Equipment, Net | 172 |
|
| Total ROU Assets | | $ | 399 |
|
| Lease Liabilities | | |
| Current Liabilities | | |
| Operating Leases | Other Current Liabilities | $ | 88 |
|
| Finance Leases | Other Current Liabilities | 42 |
|
| Noncurrent Liabilities | | |
| Operating Leases | Other Noncurrent Liabilities | 164 |
|
| Finance Leases | Long-Term Debt | 163 |
|
| Total Lease Liabilities | | $ | 457 |
|
| |
(1) | Operating lease ROU assets include compressors of $89 million and office space of $80 million. |
| |
(2) | Finance lease ROU assets include office space of $90 million and a trunkline of $28 million, both net of accumulated amortization. |
Statement of Operations InformationThe components of lease cost are as follows: |
| | | | |
| (millions) | Statement of Operations Location | Year Ended December 31, 2019 |
| Operating Lease Cost | Various (1) | $ | 110 |
|
| Finance Lease Cost | | |
| Amortization Expense | Depreciation, Depletion and Amortization | 38 |
|
| Interest Expense | Interest, Net of Amount Capitalized | 13 |
|
Short-term Lease Cost (2) | Various (1) | 424 |
|
| Sublease Income | General and Administrative | (5 | ) |
| Total Lease Cost | | $ | 580 |
|
| |
(1) | Cost classifications vary depending on the leased asset. Costs are primarily included within production expense and general and administrative expense. In addition, in accordance with the successful efforts method of accounting, certain lease costs may be capitalized when incurred and therefore, are included as part of oil and gas properties on our consolidated balance sheets. |
| |
(2) | Costs primarily relate to hydraulic fracturing services, well-to-well drilling rig contracts and other miscellaneous lease agreements. Amount excludes costs for leases with an initial term of one month or less. |
Cash Flow InformationSupplemental cash flow information is as follows: |
| | | | | | | |
| | Year Ended December 31, 2019 |
| (millions) | Operating Leases | | Finance Leases |
| Cash Paid for Amounts Included in the Measurement of Lease Liabilities | | | |
| Operating Cash Flows | $ | 74 |
| | $ | 12 |
|
| Investing Cash Flows | 36 |
| | — |
|
| Financing Cash Flows | — |
| | 42 |
|
| Non-Cash Activities | | | |
ROU Assets Obtained in Exchange for Lease Liabilities (1) | 127 |
| | 26 |
|
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| Notes to Consolidated Financial Statements | |
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(1) | Amounts exclude the impact of adopting ASC 842 on January 1, 2019. See Note 1. Summary of Significant Accounting Policies. |
Annual Lease MaturitiesAs of December 31, 2019, maturities of lease liabilities were as follows:
|
| | | | | | | | | | | |
| (millions) | Operating Leases | | Finance Leases | | Total |
| 2020 | $ | 100 |
| | $ | 52 |
| | $ | 152 |
|
| 2021 | 60 |
| | 38 |
| | 98 |
|
| 2022 | 41 |
| | 27 |
| | 68 |
|
| 2023 | 26 |
| | 23 |
| | 49 |
|
| 2024 | 15 |
| | 21 |
| | 36 |
|
| 2025 and Thereafter | 37 |
| | 86 |
| | 123 |
|
| Total Lease Liabilities, Undiscounted | 279 |
| | 247 |
| | 526 |
|
| Less: Imputed Interest | 27 |
| | 42 |
| | 69 |
|
Total Lease Liabilities (1) | $ | 252 |
| | $ | 205 |
| | $ | 457 |
|
| |
(1) | Includes the current portions of $88 million and $42 million for operating and finance leases, respectively. |
Lease CommitmentsSee Note 12. Commitments and Contingencies for lease commitments as of December 31, 2019.
Other InformationAs of December 31, 2019, other information related to our leases is as follows: |
| | | | | |
| | Operating Leases | | Finance Leases |
| Weighted-Average Remaining Lease Term | 4.9 years |
| | 7.5 years |
|
| Weighted-Average Discount Rate | 4.05 | % | | 4.96 | % |
Note 10. Impairments
2019 ImpairmentsIn fourth quarter 2019, we determined that the continued depressed commodity price environment and performance of certain of our US onshore basins indicated possible impairment of our proved oil and gas properties in our US onshore business. Following our impairment analysis, we recorded impairment expense of $1.2 billion to our Eagle Ford Shale proved properties, primarily as a result of significant decreases in NGL and natural gas prices, partially offset by lower capital and operating costs. The fair value of approximately $600 million was estimated using the income approach, utilizing a discounted cash flow model. The cash flow model included management's estimates of future production, commodity prices based on published forward commodity price curves, operating and development costs, and a risk-adjusted discount rate. As of December 31, 2019, we had $100 million of undeveloped leasehold costs related to our Eagle Ford Shale unproved properties that were not impaired and for which we believe future development scenarios exist to recover these costs.
2018 ImpairmentsIn 2018, upon classification of the Gulf of Mexico properties as assets held for sale, we recognized impairment expense of $168 million. Additionally, in fourth quarter 2018, we recorded impairment expense of $38 million, $37 million of which related to changes in construction plans for certain midstream assets.
In fourth quarter 2018, we considered changes to facts and circumstances, particularly the decline in WTI strip pricing, increases in operating and capital costs, as well as our development plans, and concluded that it was more likely than not that the fair value of our Texas reporting unit was less than its carrying amount. As a result, we recognized a goodwill impairment of $1.3 billion.
2017 ImpairmentsIn 2017, we recorded impairment expense of $70 million primarily related to our decision not to pursue development of the Troubadour natural gas discovery in the Gulf of Mexico.
Note 11. Exit Cost – Transportation Commitments
In connection with the divestiture of Marcellus Shale upstream assets in 2017, we retained certain long-term financial commitments to pay transportation fees on certain pipelines in the Marcellus Basin. As of December 31, 2019, our undiscounted financial commitment for the remaining obligations under these agreements, which have remaining terms of three to fourteen years, was approximately $1.0 billion, which excludes the impact of ongoing mitigation activities to reduce and offset this cost. See Note 4. Acquisitions and Divestitures and Note 12. Commitments and Contingencies. Our efforts to mitigate and thereby reduce these obligations primarily include permanent assignment of capacity, negotiation of capacity releases and utilization of capacity through purchase and transport of third-party natural gas. Revenues and expenses associated with mitigation activities are recorded in sales of purchased oil and gas and cost of purchased oil and gas, respectively, in our consolidated statements of operations. In the event we execute a permanent assignment of capacity, we no
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February 15, 2018, respectively. We may redeem some or all of the senior notes at any time at the applicable redemption price, plus accrued interest, if any. The senior notes were issued at a discount of $4 million and debt issuance costs incurred totaled $11 million, both of which are reflected as a reduction of long-term debt and are amortized over the life of the notes. Proceeds of $1.1 billion from the issuance of senior notes were used solely to fund the tender offer and the redemption of $1.1 billion of our 8.25% senior notes due March 1, 2019. As a result, we paid a premium of $96 million to the holders of the 8.25% senior notes and recognized a loss of $98 million in third quarter 2017, which is reflected in other non-operating (income) expense in our consolidated statements of operations.
Leviathan Term Loan Facility On February 24, 2017, Noble Energy Mediterranean Ltd. (NEML), a wholly-owned subsidiary of Noble Energy, entered into a facility agreement (Leviathan Term Loan Facility) which provided for a limited recourse secured term loan facility with an aggregate principal borrowing amount of up to $1.0 billion, of which $625 million was initially committed. Any amounts borrowed under the Leviathan Term Loan Facility would have been available to fund a portion of our share of costs for the initial phase of development of the Leviathan field. No amounts were ever drawn on the facility, which was terminated in December 2018.
Fair Value of Debt See Note 14. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of debt.Capital Lease Obligations �� The amount of the capital lease obligation is based on the discounted present value of future minimum lease payments, and therefore does not reflect future cash lease payments. Amounts due within one year equal the amount by which the capital lease obligation is expected to be reduced during the next 12 months. See Note 11. Commitments and Contingencies for future capital lease payments.Annual Debt MaturitiesAnnual maturities of outstanding debt, excluding capital lease payments, as of December 31, 2018 are as follows: |
| | | |
| (millions) | Debt Principal Payments |
| 2019 | $ | — |
|
| 2020 | — |
|
| 2021 | 1,500 |
|
| 2022 | — |
|
| 2023 | 160 |
|
| Thereafter | 4,792 |
|
| Total | $ | 6,452 |
|
Note 10. Marcellus Shale Firm Transportation Commitments
On June 28, 2017, we closed the sale of our Marcellus Shale upstream assets, which were primarily natural gas properties. In connection with the divestiture, we retained certain financial commitments on pipelines flowing natural gas production inside and outside of the Marcellus Basin. These financial commitments represent commitments to pay transportation fees; thus, we have no commitment to physically transport minimum volumes of natural gas.
Since closing, we have continued efforts to commercialize these firm transportation commitments including the permanent assignment of capacity, negotiation of capacity releases, utilization of capacity through purchase and transport of third-party natural gas, and other potential arrangements. In the event we execute a permanent assignment of capacity, we no longer have a contractual obligation to the pipeline company and, as such, our gross contractualfinancial commitment is reduced. In the event we execute a capacity release or utilize the capacity through the purchase and transport of third-party natural gas, we remain the primary obligor to the pipeline company. While our gross contractualfinancial commitment is not reduced, except through use under those arrangements, we would receive future cash payments from the third-parties with whom we negotiated a capacity release or from the sale of purchased natural gas to third-parties. As a result of our mitigation activities, we reduced and offset our financial obligations by approximately $38 million and $8 million in 2019 and 2018, respectively.
As of December 31, 2018, our gross retained firm transportation commitment for the remaining obligations under these agreements, which have remaining terms of approximately four to fifteen years, is approximately $1.5 billion, undiscounted. See Note 11. Commitments and Contingencies.One of the retained contracts relates to the Texas Eastern Pipeline. This contract is being fully utilized through a capacity release agreement with the acquirer of the Marcellus Shale upstream assets. The financial commitment on this contract is being fully mitigated by a netback agreement with the purchaser.
One of the retained contracts relates to the Appalachian Gateway Project. In 2017, we recorded an exit cost of $41 million, discounted, related to this contract, as we no longer have production to satisfy the commitment and do not plan to utilize this capacity in the future.
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| Notes to Consolidated Financial Statements | |
Additional retained contracts relate to the Leach Xpress and Rayne Xpress (Leach/Rayne Xpress) pipelines. In 2017, we permanently assigned a portion of the capacity, recording an exit cost of $52 million, discounted, related to future commitments to the third-party. Throughout 2018, we mitigated the impact of the remaining capacity through purchasing third-party natural gas and selling the natural gas to other third parties at prevailing market prices. Revenues and expenses associated with these activities are recorded on a gross basis, as we act as a principal in these arrangements by assuming control of the purchased commodity before it is transferred to the customer.
In addition to the retained firm transportation commitments, we also have the following accrued discounted liabilities associated with the exit cost activities described above: |
| | | | | | | | |
| | | December 31, |
| (millions) | | 2018 | | 2017 |
| Balance at Beginning of Period | | $ | 90 |
| | $ | — |
|
| Marcellus Exit Cost Accrual | | — |
| | 93 |
|
| Payments, Net of Accretion | | (10 | ) | | (3 | ) |
| Balance at End of Period | | $ | 80 |
| | $ | 90 |
|
| Less Current Portion Included in Other Current Liabilities | | 13 |
| | 14 |
|
| Long-term Portion Included in Other Noncurrent Liabilities | | $ | 67 |
| | $ | 76 |
|
Two additional retained contracts relate to the WB Xpress and NEXUS pipelines. In fourth quarter 2018, we entered into capacity release agreements with third parties extending through March and October 2020, respectively. Revenues and expenses associated with these agreements, as well as those associated with purchasing and selling third-party natural gas to mitigate Leach/Rayne Xpress capacity, are as follows: |
| | | | | | | | | | | | | | |
| | | | | Year Ended December 31, |
| (millions) | | Statements of Operations Location | | 2018 | | 2017 | | 2016 |
| Sales of Purchased Gas | | Sales of Purchased Oil and Gas and Other | | $ | 113 |
| | $ | — |
| | $ | — |
|
| | | | | | | | | |
| Cost of Purchased of Gas | | Other Operating Expense, Net | | 108 |
| | — |
| | — |
|
Utilized Firm Transportation Expense (1) | | Other Operating Expense, Net | | 29 |
| | — |
| | — |
|
| Unutilized Firm Transportation Expense | | Other Operating Expense, Net | | 3 |
| | — |
| | — |
|
| Cost of Purchased Gas, Total | | Other Operating Expense, Net | | $ | 140 |
| | $ | — |
| | $ | — |
|
| |
(1)
| Includes the net impact of the difference in the firm transportation contract rates and the rates agreed to in the capacity releases. Additionally, amount includes transportation expense associated with our transport of purchased natural gas on Leach/Rayne Xpress. |
We expect to continue our commercialization actions, including utilizing pipeline capacity through purchases of third-party natural gas and sales to other third parties, to mitigate these firm transportation commitments. Some of our commercialization efforts may require pipeline and/or FERC approval to ultimately reduce the financial commitment associated with these contracts. If we determine that we will not utilize a portion, or all, of the contracted pipeline capacity, we will accrue a liability at fair value for the net amount of the estimated remaining financial commitment. We cannot guarantee our commercialization efforts will be successful and we may recognize substantial future liabilities. See Note 5. Acquisitions and DivestituresPermanent Assignment.Subsequent Event In January 2019, we executed agreements on Leach/the Leach Xpress and Rayne Xpress pipelines to permanently assign the remaining capacity to a third-party effective January 1, 2021, extending through the remainder of the contract term.contract. The permanent assignment reducesreduced our total undiscounted financial commitment under the Marcellus Shale firm transportation contracts by approximately $350 million. In January 2019,million, undiscounted. As a result of the assignment, we recorded firm transportation exit costs ofcost at a fair value $92 million, representing the discounted, related to future commitmentspresent value of our remaining obligation to the third-party. We will continue efforts to mitigate the impact of these transportation agreements during 2019 andthrough 2020.
Note 11. Commitments and Contingencies
Legal Proceedings We are involved in various legal proceedings in the ordinary course of business. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters and we believe that the ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations or cash flows.
Colorado Air Matter In April 2015, we entered into a joint consent decree (Consent Decree) with the US Environmental Protection Agency (EPA), US Department of Justice, and State of Colorado to improve emission control systems at a number of our condensate storage tanks that are part of our upstream crude oil and natural gas operations within the Non-Attainment Area of the DJ Basin. The Consent Decree was entered by the US District Court for the District of Colorado on June 2, 2015.
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| Notes to Consolidated Financial Statements | |
The Consent Decree, which alleges violations of the Colorado Air Pollution Prevention and Control Act and Colorado’s federal approved State Implementation Plan, specifically Colorado Air Quality Control Commission Regulation Number 7, requires us to perform certain corrective actions, to complete mitigation projects, to complete supplemental environmental projects (SEP), and to pay a civil penalty.Exit Costs associated with the settlement consist of $5 million in civil penalties which were paid in 2015. Mitigation costs of $4 million and SEP costs of $4 million are being expended in accordance with schedules established in the Consent Decree. Costs associated with the injunctive relief are also being expended in accordance with schedules established in the Consent Decree. Since 2015, we have incurred approximately $84 million, of which $77 million was incurred to undertake corrective actions at certain tank systems following the outcome of adequacy of design evaluations and certain operation and maintenance activities to handle potential peak instantaneous vapor flow rates. Future costs associated with injunctive relief are not yet precisely quantifiable as we are continually evaluating various approaches to meet the ongoing obligations of the Consent Decree.
Overall compliance with the Consent Decree has resulted in the temporary shut-in and permanent plugging and abandonment of certain wells and associated tank batteries. Consent Decree compliance could result in additional temporary shut-ins and permanent plugging and abandonment of certain wells and associated tank batteries. The Consent Decree sets forth a detailed compliance schedule with deadlines for achievement of milestones through early 2019 that may be extended depending on certain situations. The Consent Decree contains additional obligations for ongoing inspection and monitoring beyond that which is required under existing Colorado regulations.
We have concluded that the penalties, injunctive relief, plugging and abandonment activities, and mitigation expenditures that result from this settlement, based on currently available information will not have, a material adverse effect on our financial position, results of operations or cash flows. See Note 8. Asset Retirement Obligations.Colorado Water Quality Control Division Matter In January 2017, we received a Notice of Violation/Cease and Desist Order (NOV/CDO) advising us of alleged violations of the Colorado Water Quality Control Act (Act) and its implementing regulations as it relates to our Colorado Discharge Permit System General Permit for construction activities associated with oil and gas exploration and/or production within our Wells Ranch Drilling and Production field located in Weld County, Colorado (Permit). The NOV/CDO further orders us to cease and desist from all violations of the Act, the regulations and the Permit and to undertake certain corrective actions. In October 2018, we met with enforcement staff at the Colorado Department of Public Health and Environment (CDPHE) to discuss a potential settlement of the alleged violations. Given the ongoing status of such settlement discussions, we are unable to predict the ultimate outcome of this action at this time but believe that the resolution of this action will not have a material adverse effect on our financial position, results of operations or cash flows.
Colorado Oil and Gas Conservation Commission Administrative Order on Consent In July 2018, we resolved by Administrative Order on Consent (AOC) with the Colorado Oil and Gas Conservation Commission (COGCC) allegations of noncompliance associated with site preparation and stabilization at an oil and gas location in Weld County, Colorado. The AOC required us to pay an administrative penalty of $135 thousand ($41 thousand of which is deferred subject to a nine-month compliance schedule) and to complete certain corrective actions at five oil and gas locations in Weld County, Colorado. We have concluded that the resolution of this action did not have a material adverse effect on our financial position, results of operations or cash flows.
Colorado Mechanical Integrity Testing Matter In September 2018, we resolved by AOC with the COGCC administrative claims for allegations of noncompliance of State mechanical integrity testing rules at eight shut-in wells in Weld County, Colorado. The AOC includes an administrative penalty of $1.6 million, of which $1.4 million of the total penalty is to be offset by our commensurate contribution to two public projects and our requirement to repair or plug and abandon each of the eight wells and to submit to COGCC certain environmental data. We have concluded that the resolution of this action did not have a material adverse effect on our financial position, results of operations or cash flows.
Colorado Clean Water Act Referral Notice In September 2018, we received a letter from the US Department of Justice providing notification of referral from the EPA of alleged Clean Water Act violations at an upstream production facility and a midstream gathering facility in Weld County, Colorado. The letter requests an opportunity to discuss settlement of the alleged violations. Given the uncertainty associated with enforcement actions of this nature, we are unable to predict the ultimate outcome of this action at this time, but believe that the resolution of this action will not have a material adverse effect on our financial position, results of operations or cash flows.
Marcellus Shale Firm Transportation Obligations As part of our Marcellus Shale upstream divestiture, we retained certain transportation and gathering obligations to flow Marcellus Shale natural gas production to various markets inside and outside of the Marcellus Basin. See Note 10. Marcellus Shale Firm Transportation Commitments.Other Transportation and Gathering Obligations We have transportation and gathering obligations to flow US onshore production, primarily in the DJ Basin, to various markets. CertainReconciliation of these contracts require us to make payments for any
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| Notes to Consolidated Financial Statements | |
shortfalls in delivering or transporting minimum volumes under the commitments. As properties are undergoing development activities, we may experience temporary shortfalls until production volumes increase to meet or exceed the minimum volume commitments and will incur expense related to volume deficiencies and/or unutilized commitments. We expect to continue to incur expense related to deficiency and/or unutilized commitments in the near-term. These amounts are recorded as marketing expense in our consolidated statements of operations.
Our total financial commitment for these agreements, which have remaining terms of two to ten years, is approximately $612 million, undiscounted. The commitment is included in the table below.
Non-Cancelable Leases and Other Commitments Wehold leases and other commitments for drilling rigs, buildings, equipment and other property. Rental expense for office buildings and oil and gas operations equipment was $90 million in 2018, $69 million in 2017, and $76 million in 2016.
Minimum commitments as ofaccrued exit costs at December 31,
2018 consist of the following:2019 is as follows: |
| | | | | | | | |
| | | December 31, |
| (millions) | | 2019 | | 2018 |
| Balance at Beginning of Period | | $ | 80 |
| | $ | 90 |
|
Exit Cost Accrual(1) | | 88 |
| | — |
|
| Payments, Net of Accretion | | (5 | ) | | (10 | ) |
| Balance at End of Period | | $ | 163 |
| | $ | 80 |
|
| Less Current Portion Included in Other Current Liabilities | | 34 |
| | 13 |
|
| Long-term Portion Included in Other Noncurrent Liabilities | | $ | 129 |
| | $ | 67 |
|
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| (millions) | | Purchase and Service Obligations | | Marcellus Shale Firm Transportation and Other Obligations (1) | | Gathering, Transportation & Processing Obligations | | Operating Lease Obligations (2) | | Capital Lease Obligations (2) | | Total |
| 2019 | | $ | 197 |
| | $ | 123 |
| | $ | 151 |
| | $ | 91 |
| | $ | 52 |
| | $ | 614 |
|
| 2020 | | 29 |
| | 122 |
| | 129 |
| | 74 |
| | 46 |
| | 400 |
|
| 2021 | | 13 |
| | 121 |
| | 103 |
| | 59 |
| | 31 |
| | 327 |
|
| 2022 | | 6 |
| | 118 |
| | 67 |
| | 62 |
| | 22 |
| | 275 |
|
| 2023 | | 21 |
| | 113 |
| | 66 |
| | 50 |
| | 20 |
| | 270 |
|
| 2024 and Thereafter | | 5 |
| | 934 |
| | 285 |
| | 176 |
| | 104 |
| | 1,504 |
|
| Total | | $ | 271 |
| | $ | 1,531 |
| | $ | 801 |
| | $ | 512 |
| | $ | 275 |
| | $ | 3,390 |
|
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(1) | Amount includes $92 million exit cost obligations resulting fromfor the permanent assigned discussed above, offset by a permanent capacity assignment. See Note 10. Marcellus Shale Firm Transportation Commitments. |
| |
(2)
| Annual lease payments, net to our interest, exclude regular maintenance and operational costs. See Note 9. Long-Term Debt. |
Note 12. Income Taxes
Components of income (loss) from operations before income taxes areRevenues and expenses associated with these long-term financial commitments, including mitigation activities discussed above, were as follows: |
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| (millions) | | 2018 | | 2017 | | 2016 |
| Domestic | | $ | (953 | ) | | $ | (2,831 | ) | | $ | (1,859 | ) |
| Foreign | | 1,093 |
| | 640 |
| | 87 |
|
| Total | | $ | 140 |
| | $ | (2,191 | ) | | $ | (1,772 | ) |
|
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| (millions) | | 2019 | | 2018 | | 2017 |
| Sales of Purchased Gas | | $ | 90 |
| | $ | 113 |
| | $ | — |
|
| | | | | | | |
| Cost of Purchased of Gas | | 85 |
| | 108 |
| | — |
|
| Utilized Firm Transportation Expense | | 57 |
| | 29 |
| | — |
|
| Unutilized Firm Transportation Expense | | 1 |
| | 3 |
| | — |
|
| Cost of Purchased Gas, Total | | $ | 143 |
| | $ | 140 |
| | $ | — |
|
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| Notes to Consolidated Financial Statements | |
The income tax provision (benefit) consists of the following: |
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| (millions, except percentages) | | 2018 | | 2017 | | 2016 |
| Current Taxes | | | | | | |
| Federal | | $ | 22 |
| | $ | (11 | ) | | $ | (4 | ) |
| State | | 2 |
| | 1 |
| | 5 |
|
| Foreign | | 172 |
| | 96 |
| | 196 |
|
| Total Current | | $ | 196 |
| | $ | 86 |
| | $ | 197 |
|
| Deferred Taxes | | | | | | |
| Federal | | $ | (123 | ) | | $ | (1,258 | ) | | $ | (784 | ) |
| State | | (7 | ) | | (8 | ) | | (24 | ) |
| Foreign | | 60 |
| | 39 |
| | (176 | ) |
| Total Deferred | | $ | (70 | ) | | $ | (1,227 | ) | | $ | (984 | ) |
| Total Income Tax Provision (Benefit) Attributable to Noble Energy | | $ | 126 |
| | $ | (1,141 | ) | | $ | (787 | ) |
| Effective Tax Rate | | 90.0 | % | | 52.1 | % | | 44.4 | % |
A reconciliation of the federal statutory tax rate to the effective tax rate is as follows: |
| | | | | | | | | |
| | | Year Ended December 31, |
| (percentages) | | 2018 | | 2017 | | 2016 |
Federal Statutory Rate (1) | | 21.0 | % | | 35.0 | % | | 35.0 | % |
| Effect of | | | | | | |
| Goodwill Impairment | | 192.5 |
| | — |
| | — |
|
Change in Valuation Allowance (1) | | (170.2 | ) | | (17.4 | ) | | (2.0 | ) |
US and Foreign Statutory Rate Change (1) | | 80.7 |
| | 23.5 |
| | 1.6 |
|
Accumulated Undistributed Foreign Earnings (1) | | — |
| | 11.0 |
| | 7.2 |
|
Transition Tax (1) | | — |
| | (4.8 | ) | | — |
|
| Difference Between US and Foreign Rates | | 17.9 |
| | 1.8 |
| | (0.1 | ) |
| Earnings of Equity Method Investees | | (20.1 | ) | | 1.9 |
| | 1.0 |
|
| Noncontrolling Interests | | (12.1 | ) | | 1.1 |
| | 0.4 |
|
| State Taxes, Net of Federal Benefit | | 0.9 |
| | 0.3 |
| | 1.3 |
|
| Foreign Exploration Loss | | (35.6 | ) | | — |
| | — |
|
Global Intangible Low-Taxed Income (GILTI) (1) | | 24.2 |
| | — |
| | — |
|
| Return to Provision | | (17.1 | ) | | (0.1 | ) | | (0.2 | ) |
| Audit Settlement | | 5.1 |
| | 0.1 |
| | (0.2 | ) |
| Oil Profits Tax - Israel | | 3.3 |
| | (0.1 | ) | | — |
|
| Other, Net | | (0.5 | ) | | (0.2 | ) | | 0.4 |
|
| Effective Rate | | 90.0 | % | | 52.1 | % | | 44.4 | % |
(1) See Tax Reform Legislation and Accumulated Undistributed Earnings of Foreign Subsidiaries, below.
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Deferred tax assets and liabilities resulted from the following:
|
| | | | | | | | |
| | | December 31, |
| (millions) | | 2018 | | 2017 |
| Deferred Tax Assets | | | | |
| Loss Carryforwards | | $ | 589 |
| | $ | 902 |
|
| Employee Compensation and Benefits | | 92 |
| | 97 |
|
| Mark to Market of Commodity Derivative Instruments | | (27 | ) | | 7 |
|
| Foreign Tax Credits | | 138 |
| | 366 |
|
| Other | | 157 |
| | 104 |
|
| Total Deferred Tax Assets | | $ | 949 |
| | $ | 1,476 |
|
| Valuation Allowance - Foreign Loss Carryforwards and Foreign Tax Credits | | (320 | ) | | (549 | ) |
| Net Deferred Tax Assets | | $ | 629 |
| | $ | 927 |
|
| Deferred Tax Liabilities | | | | |
| Property, Plant and Equipment, Principally Due to Differences in Depreciation, Amortization, Lease Impairment and Abandonments | | (1,669 | ) | | (2,029 | ) |
| Total Deferred Tax Liability | | $ | (1,669 | ) | | $ | (2,029 | ) |
| Net Deferred Tax Liability | | $ | (1,040 | ) | | $ | (1,102 | ) |
Net deferred tax assets and liabilities were classified in the consolidated balance sheets as follows: |
| | | | | | | | |
| | | December 31, |
| (millions) | | 2018 | | 2017 |
| Deferred Income Tax Asset - Noncurrent | | $ | 21 |
| | $ | 25 |
|
| Deferred Income Tax Liability - Noncurrent | | (1,061 | ) | | (1,127 | ) |
| Net Deferred Tax Liability | | $ | (1,040 | ) | | $ | (1,102 | ) |
Tax Reform LegislationOn December 22, 2017, the US Congress enacted Tax Reform Legislation, which made significant changes to US federal income tax law, including a reduction in the federal corporate tax rate to 21% effective January 1, 2018. The SEC staff issued SAB 118 which allowed registrants to report provisional amounts for the income tax effects specific to Tax Reform Legislation for which accounting was incomplete but a reasonable estimate could be determined. We reported certain provisional amounts in fourth quarter 2017, some of which were adjusted in 2018 based on changes in estimates, including changes based on further guidance provided by the Internal Revenue Service (IRS).
Provisional amounts recorded in 2017 and changes in estimates reported in 2018 are as follows:
Remeasurement of Deferred Taxes In accordance with US GAAP, we recognized the effect of the rate change on deferred tax assets and liabilities in the period in which the tax rate change was enacted, resulting in the recognition of a provisional deferred tax benefit of $500 million at December 31, 2017. Further remeasurements of these deferred taxes in 2018 were associated with the return to provision resulted in a $10 million deferred tax benefit.
Transition Tax (Toll Tax) Tax Reform Legislation provided for a toll tax on a one-time “deemed repatriation” of accumulated foreign earnings for the year ended December 31, 2017. Based on early interpretations of the law, we recognized additional taxable income in 2017 of $767 million associated with the toll tax, which was fully offset by net operating losses (NOLs), and recorded corresponding deemed foreign tax credits of $164 million, against which we recorded a full valuation allowance.
On April 2, 2018, the US Department of the Treasury and the IRS released Notice 2018-26, signaling intent to issue regulations related to the toll tax for the year ended December 31, 2017. Notice 2018-26 clarified that an Internal Revenue Code Section 965(n) election is available with respect to both current and prior year NOLs. As a result, we released $252 million of the valuation allowance recorded against foreign tax credits to be utilized against the estimated $268 million toll tax liability recorded as of December 31, 2017. This resulted in a $252 million tax benefit and a corresponding expense of $107 million for the tax rate change adjustment on the previously utilized NOL's. The impact on first quarter 2018 total tax expense, related to this additional guidance, was a net $145 million discrete tax benefit.
During fourth quarter 2018, the toll tax calculations were finalized in conjunction with filing of the US tax return, resulting in a $261 million toll tax against which $240 million of foreign tax credits were utilized. This resulted in a $21 million liability
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
payable in installments over eight years beginning in 2018. The additional impact recorded during fourth quarter 2018 was a net $5 million tax expense.
Global Intangible Low-Taxed Income (GILTI) Tax Reform Legislation also introduced a new tax on global intangible low-taxed income (GILTI). Further analysis and legal interpretation has resulted in identifying certain foreign oil related income (FORI) activity as GILTI income which will be offset by NOL carryforwards rather than the 50% deduction and related foreign tax credits. As a result of utilizing our NOL to offset the GILTI inclusion, we recognized tax expense of $34 million for 2018 GILTI associated with FORI from investments in operating assets in Equatorial Guinea and operations in Israel. We are making an accounting policy election to not record deferred taxes related to GILTI.
Other Provisions Tax Reform Legislation is a comprehensive bill containing other provisions that do not materially affect us. The ultimate impact may differ from our estimates if additional regulatory guidance is issued. We are closely monitoring the provision which revised and broadened the former Section 163(j) interest expense limitation rules. In tax years subsequent to 2021 the basis of the limitation calculation will change to be roughly equivalent to EBIT at which time we expect to be subject to an interest expense limitation. The interest expense not deducted due to limitation has an indefinite carryover period.
Deferred Tax Assets Our estimated pre-tax NOL carryforwards totaled approximately $2.4 billion at December 31, 2018, of which US federal income tax NOL carryforwards totaled approximately $1.7 billion and foreign NOL carryforwards were $670 million.
In assessing the realizability of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income in the appropriate tax jurisdictions during the periods in which those temporary differences become deductible. We consider the scheduled reversal of deferred tax liabilities, current financial position, results of operations, projected future taxable income and tax planning strategies as well as current and forecasted business economics in the oil and gas industry. Based on the level of historical taxable income and projections for future taxable income, we believe it is more likely than not that we will realize the benefits of these NOL carryforwards. However, the amount of the deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced.
We currently have a valuation allowance on the deferred tax assets associated with foreign loss carryforwards and foreign tax credits. The valuation allowance on foreign loss carryforwards totaled $187 million and $183 million in 2018 and 2017, respectively. The valuation allowance on foreign tax credits totaled $132 million and $366 million in 2018 and 2017, respectively. As noted above, in first quarter 2018 we released $252 million of the valuation allowance recorded against the foreign tax credits and in fourth quarter 2018, we made further return to provision adjustments based on the tax return filing.
Clayton Williams Energy AcquisitionOn April 24, 2017, we completed the Clayton Williams Energy Acquisition. For federal income tax purposes, the transaction qualified as a tax free merger and we acquired carryover tax basis in Clayton Williams Energy's assets and liabilities. Our purchase price allocation is finalized and we recorded a deferred tax liability of $307 million, adjusted for the new US statutory rate, which includes a deferred tax asset for federal pre-tax NOLs of approximately $450 million. The merger resulted in a change of control for federal income tax purposes, and the NOL usage will be subject to an annual limitation in part based on Clayton Williams Energy's value at the date of the merger. We anticipate full utilization of the total NOL prior to expiration.
Effective Tax Rate Our effective tax rate increased in 2018 as compared with 2017, primarily due to the fourth quarter 2018 goodwill impairment for which there is no tax benefit and the deferred tax expense of $34 million for GILTI. This increase was reduced by a deferred tax benefit of $145 million recorded discretely in the current year, as discussed above, and a deferred tax benefit of $50 million associated with a write-off of foreign exploration losses. The increase in current income tax expense during 2018 as compared with 2017 is primarily due to foreign taxes on the gain recognized with the first quarter 2018 divestiture of a 7.5% working interest in the Tamar field. The decrease in deferred income tax benefit during 2018 as compared to 2017 is due to the significant deferred tax benefit recorded in 2017 associated with the revaluation of the US deferred tax liability at the reduced future tax rate.
Accumulated Undistributed Earnings of Foreign SubsidiariesDuring 2016, we reduced the deferred tax liability associated with unremitted foreign earnings, net of foreign tax credits, to $240 million. In 2017, as a result of Tax Reform Legislation, which established a new territorial tax regime, we reversed the deferred tax liability recorded in 2016, resulting in a deferred tax benefit of $240 million. As of December 31, 2018, there is no expected withholding tax impact upon actual distribution of earnings and as such, we have not recorded any tax associated with unremitted earnings.
Israeli Tax LawEffective December 21, 2016, the Israeli government decreased the corporate income tax rate from 25% to 24% for 2017 and from 24% to 23% effective January 2018. The full impact of the rate reduction was recognized in 2017, decreasing deferred tax expense by $12 million.
Furthermore, our Israeli operations are subject to the Natural Resources Profits Taxation Law, 2011 (the Law), which imposes a separate additional tax on profits from oil and gas activities (Oil Profits Tax). The Oil Profits Tax is calculated by dividing net
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
accumulated revenue generated by each separate project by its cumulative investments as defined within the Law. Once the revenue factor (R Factor) reaches 1.5, a tax rate of 20% is imposed; as the ratio increases to a maximum of 2.3, the Oil Profits Tax increases progressively up to a maximum rate of 50%. The Oil Profits Tax provides for a corporate tax rate adjustment based on the corporate income tax rate, which is currently 23%. To the extent the corporate income tax rate exceeds 18%, a reduction in the Oil Profits Tax rate is calculated. At the current corporate tax rate, the Oil Profits Tax rate is 46.8%. The Oil Profits Tax is deductible for Israeli corporate tax purposes. Our Tamar and Leviathan projects are both subject to the Oil Profits Tax and are expected to pay at the maximum rate.
Unrecognized Tax BenefitsWe file a consolidated income tax return in the US federal jurisdiction, and we file income tax returns in various states and foreign jurisdictions. Our income tax returns are routinely audited by the applicable revenue authorities, and provisions are made in the financial statements for differences between positions taken in tax returns and amounts recognized in the financial statements in anticipation of audit results.
In our major tax jurisdictions, the earliest years remaining open to examination are: US - 2015, Israel - 2015 (2013 with respect to Israel Oil Profits Tax) and Equatorial Guinea - 2013. Our policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense. As of December 31, 2018 and 2017, we had no unrecognized tax benefits.
Note 12. Commitments and Contingencies
Legal Proceedings We are involved in various legal proceedings in the ordinary course of business. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters and we believe that the ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations or cash flows.
Colorado Air MatterIn April 2015, we entered into a joint consent decree (Consent Decree) with the US Environmental Protection Agency (EPA), US Department of Justice, and State of Colorado to improve emission control systems at a number of our condensate storage tanks that are part of our upstream crude oil and natural gas operations within the Non-Attainment Area of the DJ Basin. Costs associated with the settlement consist of $5 million in civil penalties which were paid in 2015. Mitigation costs of $4 million and supplemental environmental project costs of $4 million are being expended in accordance with schedules established in the Consent Decree. Costs associated with the injunctive relief, including plugging and abandonment of certain wells and facilities, are also being expended in accordance with schedules established in the Consent Decree.
We have concluded that the penalties, injunctive relief and mitigation expenditures that result from this settlement, based on currently available information, will not have a material adverse effect on our financial position, results of operations or cash flows. See Note 7. Asset Retirement Obligations.
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Colorado Water Quality Control Division MatterIn October 2019, we resolved by Compliance Order on Consent (COC) with the Colorado Department of Public Health & Environment allegations of noncompliance with the Colorado Water Quality Act relating to our Colorado Discharge Permit System General Permit for construction activities associated with oil and gas exploration and/or production within our Wells Ranch Drilling and Production field located in Weld County, Colorado. The COC required us to pay a penalty of $57 thousand and to contribute $126 thousand toward a State-managed supplemental environmental project. We have concluded that the resolution of this action did not have a material adverse effect on our financial position, results of operations or cash flows.
Colorado Clean Water Act Referral NoticeIn September 2018, we received a letter from the US Department of Justice providing notification of referral from the EPA of alleged Clean Water Act violations at an upstream production facility and a midstream gathering facility in Weld County, Colorado. In April 2019, we met with the DOJ and Environmental Protection Agency enforcement personnel to discuss potential settlement of the alleged violations. Given the ongoing status of settlement discussions, we are currently unable to predict the ultimate outcome of this action, but believe the resolution will not have a material adverse effect on our financial position, results of operations or cash flows.
Marcellus Shale Firm Transportation ObligationsAs part of our Marcellus Shale upstream divestiture, we retained certain transportation obligations to flow Marcellus Shale natural gas production to various markets. See Note 11. Exit Cost – Transportation Commitments. Other Gathering and Transportation ObligationsAs part of our normal course of business, we enter into agreements to transport minimum volumes in the US onshore and Eastern Mediterranean. In the US onshore, primarily in the DJ Basin, certain of these contracts require us to make payments for any shortfalls in delivering or transporting minimum volumes under the commitments. As properties are undergoing development activities, we may experience temporary shortfalls until production volumes increase to meet or exceed the minimum volume commitments and will incur expense related to volume deficiencies and/or unutilized commitments. We expect to continue to incur expense related to deficiency and/or unutilized commitments in the near-term. These amounts are recorded as marketing expense in our consolidated statements of operations. In the Eastern Mediterranean, regional export contracts contain minimum transportation commitments. For US onshore and Eastern Mediterranean agreements, which have remaining terms of one to 12 years, our total financial commitment is approximately $921 million, undiscounted. The commitments are included in the table below.
Mezzanine Equity Commitment In March 2019, Noble Midstream Partners obtained a $200 million preferred equity commitment. $100 million of the commitment funded immediately and the remaining $100 million is available for funding until March 2020, subject to certain conditions precedent. See Note1. Summary of Significant Accounting Policies and Note 4. Acquisitions and Divestitures. Minimum Commitments Minimum commitments as of December 31, 2019 consist of the following: |
| | | | | | | | | | | | | | | | | | | | | | | |
| (millions) | Purchase and Service Obligations | | Marcellus Shale Firm Transportation Obligations (1) | | Gathering, Transportation & Processing Obligations (2) | | Operating Lease Obligations (3) | | Finance Lease Obligations (3) | | Total |
| 2020 | $ | 135 |
| | $ | 143 |
| | $ | 174 |
| | $ | 100 |
| | $ | 52 |
| | $ | 604 |
|
| 2021 | 28 |
| | 102 |
| | 176 |
| | 60 |
| | 38 |
| | 404 |
|
| 2022 | 14 |
| | 85 |
| | 156 |
| | 41 |
| | 27 |
| | 323 |
|
| 2023 | 30 |
| | 83 |
| | 153 |
| | 26 |
| | 23 |
| | 315 |
|
| 2024 | 2 |
| | 92 |
| | 149 |
| | 15 |
| | 21 |
| | 279 |
|
| 2025 and Thereafter | 72 |
| | 675 |
| | 334 |
| | 37 |
| | 86 |
| | 1,204 |
|
| Total | $ | 281 |
| | $ | 1,180 |
| | $ | 1,142 |
| | $ | 279 |
| | $ | 247 |
| | $ | 3,129 |
|
| |
(1) | Amount includes exit cost obligations resulting from permanent capacity assignments. See Note 11. Exit Cost – Transportation Commitments. |
| |
(2) | Amount includes US onshore and Eastern Mediterranean transportation obligations of $921 million, undiscounted, and Noble Midstream Partners obligations of $221 million, undiscounted. |
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Note 13. Income Taxes
Components of (loss) income from operations before income taxes are as follows: |
| | | | | | | | | | | |
| | Year Ended December 31, |
| (millions) | 2019 | | 2018 | | 2017 |
| Domestic | $ | (2,222 | ) | | $ | (953 | ) | | $ | (2,831 | ) |
| Foreign | 446 |
| | 1,093 |
| | 640 |
|
| Total | $ | (1,776 | ) | | $ | 140 |
| | $ | (2,191 | ) |
Income Tax Provision The income tax (benefit) provision consists of the following: |
| | | | | | | | | | | |
| | Year Ended December 31, |
| (millions, except percentages) | 2019 | | 2018 | | 2017 |
| Current Taxes | | | | | |
| Federal | $ | 1 |
| | $ | 22 |
| | $ | (11 | ) |
| State | 3 |
| | 2 |
| | 1 |
|
| Foreign | 81 |
| | 172 |
| | 96 |
|
| Total Current | $ | 85 |
| | $ | 196 |
| | $ | 86 |
|
| Deferred Taxes | | | | | |
| Federal | $ | (413 | ) | | $ | (123 | ) | | $ | (1,258 | ) |
| State | (25 | ) | | (7 | ) | | (8 | ) |
| Foreign | 10 |
| | 60 |
| | 39 |
|
| Total Deferred | $ | (428 | ) | | $ | (70 | ) | | $ | (1,227 | ) |
| Total Income Tax (Benefit) Provision Attributable to Noble Energy | $ | (343 | ) | | $ | 126 |
| | $ | (1,141 | ) |
| Effective Tax Rate | 19.3 | % | | 90.0 | % | | 52.1 | % |
The 2019 deferred income tax benefit relates to the asset impairment recorded in fourth quarter 2019. See Note 10. Impairments. The 2018 income tax provision is primarily due to current income tax expense for foreign taxes on the gain recognized for the 2018 divestiture of a 7.5% working interest in the Tamar field, partially offset by a deferred income tax benefit. The 2017 income tax benefit is due to the significant deferred tax benefit associated with the revaluation of the US deferred tax liability as a result of the reduction in the federal corporate tax rate to 21%.
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Effective Tax Rate (ETR) A reconciliation of the federal statutory tax rate to the ETR is as follows: |
| | | | | | | | |
| | Year Ended December 31, |
| (percentages) | 2019 | | 2018 | | 2017 |
| Federal Statutory Rate | 21.0 | % | | 21.0 | % | | 35.0 | % |
| Effect of | | | | | |
| Goodwill Impairment | — |
| | 192.5 |
| | — |
|
| Change in Valuation Allowance | (0.6 | ) | | (170.2 | ) | | (17.4 | ) |
| US and Foreign Statutory Rate Change | — |
| | 80.7 |
| | 23.5 |
|
| Accumulated Undistributed Foreign Earnings | — |
| | — |
| | 11.0 |
|
| Transition Tax | — |
| | — |
| | (4.8 | ) |
| Difference Between US and Foreign Rates | (0.6 | ) | | 17.9 |
| | 1.8 |
|
| Earnings of Equity Method Investments | 0.7 |
| | (20.1 | ) | | 1.9 |
|
| Noncontrolling Interests | 0.9 |
| | (12.1 | ) | | 1.1 |
|
| State Taxes | 1.1 |
| | 0.9 |
| | 0.3 |
|
| Foreign Exploration Loss | — |
| | (35.6 | ) | | — |
|
| Global Intangible Low-Taxed Income (GILTI) | (0.8 | ) | | 24.2 |
| | — |
|
| Return to Provision | — |
| | (17.1 | ) | | (0.1 | ) |
| Audit Settlement | — |
| | 5.1 |
| | 0.1 |
|
| Oil Profits Tax - Israel | (0.1 | ) | | 3.3 |
| | (0.1 | ) |
| Other, Net | (2.3 | ) | | (0.5 | ) | | (0.2 | ) |
| Effective Rate | 19.3 | % | | 90.0 | % | | 52.1 | % |
There were no material items impacting our 2019 ETR as compared to the federal statutory rate of 21%. Our 2018 ETR included a significant deferred tax benefit, discussed below, recorded as a result of the intent of the US Department of the Treasury (Treasury) and Internal Revenue Service (IRS) to issue additional regulatory guidance associated with the Tax Cuts and Jobs Act (Tax Reform Legislation) and the transition tax. In addition, the 2018 ETR was impacted by low earnings, goodwill impairment with no tax benefit, deferred tax expense of $34 million related to GILTI, discussed below, and a deferred tax benefit of $50 million associated with a write-off of foreign exploration losses. Our 2017 ETR was driven by the deferred tax benefit related to the Tax Reform Legislation, as we revalued the ending deferred tax liability at the reduced future tax rate.
Deferred Tax Assets and Liabilities Deferred tax assets and liabilities resulted from the following: |
| | | | | | | |
| | December 31, |
| (millions) | 2019 | | 2018 |
| Deferred Tax Assets | | | |
Loss Carryforwards (1) | $ | 656 |
| | $ | 589 |
|
| Employee Compensation and Benefits | 92 |
| | 92 |
|
| Mark to Market of Commodity Derivative Instruments | 11 |
| | (27 | ) |
| Foreign Tax Credits | 133 |
| | 138 |
|
| Other | 126 |
| | 157 |
|
| Total Deferred Tax Assets | $ | 1,018 |
| | $ | 949 |
|
| Valuation Allowance - Foreign Loss Carryforwards and Foreign Tax Credits | (327 | ) | | (320 | ) |
| Net Deferred Tax Assets | $ | 691 |
| | $ | 629 |
|
| Deferred Tax Liabilities | | | |
| Property, Plant and Equipment, Principally Due to Differences in Depreciation, Amortization, Lease Impairment and Abandonments | (1,338 | ) | | (1,669 | ) |
| Total Deferred Tax Liability | $ | (1,338 | ) | | $ | (1,669 | ) |
| Net Deferred Tax Liability | $ | (647 | ) | | $ | (1,040 | ) |
| |
(1) | At December 31, 2019, $459 million related to domestic tax (state and federal) and $197 million related to foreign tax. |
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Net deferred tax assets and liabilities were classified in the consolidated balance sheets as follows: |
| | | | | | | |
| | December 31, |
| (millions) | 2019 | | 2018 |
| Deferred Income Tax Asset - Noncurrent | $ | 15 |
| | $ | 21 |
|
| Deferred Income Tax Liability - Noncurrent | (662 | ) | | (1,061 | ) |
| Net Deferred Tax Liability | $ | (647 | ) | | $ | (1,040 | ) |
Our estimated pre-tax net operating loss (NOL) carryforwards totaled approximately $2.7 billion at December 31, 2019, of which US federal income tax NOL carryforwards totaled approximately $2.0 billion and foreign NOL carryforwards totaled $691 million.
We currently have a valuation allowance on the deferred tax assets associated with foreign loss carryforwards and foreign tax credits. The valuation allowance on foreign loss carryforwards totaled $192 million and $187 million in 2019 and 2018, respectively. The valuation allowance on foreign tax credits totaled $133 million and $132 million in 2019 and 2018, respectively.
Accumulated Undistributed Earnings of Foreign SubsidiariesAs of December 31, 2019, there is no expected withholding tax impact upon actual distribution of earnings and as such, we have not recorded any tax associated with unremitted earnings.
Tax Reform Legislation UpdatesSince the enactment of Tax Reform Legislation by the US Congress in December 2017, Treasury and the IRS have periodically issued guidance regarding various aspects of the new law.
Global Intangible Low-Taxed Income (GILTI) Tax Reform Legislation introduced a new tax on GILTI. Further analysis and legal interpretation has resulted in identifying certain foreign oil related income (FORI) activity as GILTI income which will be offset by NOL carryforwards rather than the 50% deduction and related foreign tax credits. As a result of utilizing our NOL to offset the GILTI inclusion, for 2019 and 2018, we recognized tax expense of $14 million and $34 million, respectively, of GILTI associated with FORI from investments in Equatorial Guinea and Israel.
In June 2019, Treasury and the IRS released new proposed regulations pertaining to GILTI, which include an election that would apply an elective high-tax exception to GILTI when the tax imposed on a tentative net tested income item exceeds an 18.5% corporate tax rate. The applicability of the high-tax exception would be tested at the level of a single qualified business unit (QBU) and would apply to all foreign corporations controlled by the same domestic shareholders. This regulation is applicable to taxable years beginning on or after the date that final regulations are published in the Federal Register. For us, this high tax exception would have the effect of reclassifying all GILTI into another classification of income, thus eliminating the GILTI/NOL offset item described above. We will continue to monitor the development of this proposed regulation.
Transition Tax (Toll Tax)Tax Reform Legislation provided for a toll tax on a one-time “deemed repatriation” of accumulated foreign earnings for the year ended December 31, 2017. In April 2018, the Treasury and the IRS released Notice 2018-26, signaling intent to issue regulations related to the toll tax for the year ended December 31, 2017. This notice clarified that an Internal Revenue Code Section 965(n) election is available with respect to both current and prior year NOLs. As a result, we released $252 million of the valuation allowance recorded against foreign tax credits to be utilized against the estimated $268 million toll tax liability recorded as of December 31, 2017. This resulted in a $252 million tax benefit and a corresponding expense of $107 million for the tax rate change adjustment on the previously utilized NOLs. The impact on first quarter 2018 total tax expense, related to this additional guidance, was a net $145 million discrete tax benefit.
During fourth quarter 2018, the toll tax calculations were finalized in conjunction with filing of the US tax return, resulting in a $261 million toll tax against which $240 million of foreign tax credits were utilized. This resulted in a $21 million liability payable in installments over eight years beginning in 2018.
Other ProvisionsTax Reform Legislation broadened the former Section 163(j) applying a net interest expense limitation equal to 30% of earnings before interest, taxes, depreciation, and amortization (EBITDA) for tax years beginning after December 31, 2017, and before January 1, 2022, after which the net interest expense limitation will be calculated as 30% of earnings before interest and taxes (EBIT). Disallowed interest may be carried forward indefinitely. In November 2018, Treasury and the IRS released proposed regulations pertaining to section 163(j) which state that any amount normally incurred as deductible DD&A, but included in a taxpayer’s cost of goods sold calculation pursuant to section 263A, is not a deduction for DD&A for purposes of determining Adjusted Taxable Income for years beginning prior to January 1, 2022. We have modified our 163(j) limitation calculation to comply and will continue to monitor the development of this proposed regulation.
Israeli Tax LawOur Israeli operations are subject to the Natural Resources Profits Taxation Law, 2011 (the Law), which imposes a separate additional tax on profits from oil and gas activities (Oil Profits Tax). The Oil Profits Tax is calculated by dividing net accumulated revenue generated by each separate project by its cumulative investments as defined within the
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Law. Once the revenue factor (R Factor) reaches 1.5, a tax rate of 20% is imposed; as the ratio increases to a maximum of 2.3, the Oil Profits Tax increases progressively up to a maximum rate of 50%. The Oil Profits Tax provides for a corporate tax rate adjustment based on the corporate income tax rate, which is currently 23%. To the extent the corporate income tax rate exceeds 18%, a reduction in the Oil Profits Tax rate is calculated. At the current corporate tax rate, the Oil Profits Tax rate is 46.8%. The Oil Profits Tax is deductible for Israeli corporate tax purposes. Our Tamar and Leviathan projects are both subject to the Oil Profits Tax and are expected to pay at the maximum rate.
Clayton Williams Energy AcquisitionIn April 2017, we completed the Clayton Williams Energy Acquisition, which qualified as a tax free merger, and acquired carryover tax basis in Clayton Williams Energy's assets and liabilities. As part of our purchase price allocation we recorded a deferred tax liability of $307 million, adjusted for the new US statutory rate, which includes a deferred tax asset for federal pre-tax NOLs of approximately $450 million. The merger resulted in a change of control for federal income tax purposes, and the NOL usage will be subject to an annual limitation in part based on Clayton Williams Energy's value at the date of the merger.
Unrecognized Tax BenefitsWe file a consolidated income tax return in the US federal jurisdiction, and we file income tax returns in various states and foreign jurisdictions. Our income tax returns are routinely audited by the applicable revenue authorities, and provisions are made in the financial statements for differences between positions taken in tax returns and amounts recognized in the financial statements in anticipation of audit results.
In our major tax jurisdictions, the earliest years remaining open to examination are: US - 2014, Israel - 2015 (2013 with respect to Israel Oil Profits Tax) and Equatorial Guinea - 2013. Our policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense. As of December 31, 2019 and 2018, we had de minimis unrecognized tax benefits.
Note 14. Derivative Instruments and Hedging Activities
Objective and Strategies for Using Derivative Instruments We may enter into crude oil and natural gas price hedging arrangements in an effort to mitigate the effects of commodity price volatility and enhance the predictability of cash flows relating to the marketing of a portion of our crude oil and natural gas production. The derivative instruments we use may include variable to fixed price commodity swaps, enhanced swaps, collars and three-way collars, sold calls and sold puts, basis swaps, swaptions and/or put options.
The fixed price swap and collar contracts entitle us (floating price payor) to receive settlement from the counterparty (fixed price payor) for each calculation period in amounts, if any, by which the settlement price for the scheduled trading days applicable for each calculation period is less than the fixed strike price or floor price. We would pay the counterparty if the settlement price for the scheduled trading days applicable for each calculation period is more than the fixed strike price or ceiling price. The amount payable by us, if the floating price is above the fixed or ceiling price, is the product of the notional quantity per calculation period and the excess of the floating price over the fixed or ceiling price in respect of each calculation period. The amount payable by the counterparty, if the floating price is below the fixed or floor price, is the product of the notional quantity per calculation period and the excess of the fixed or floor price over the floating price in respect of each calculation period.
A three-way collar consists of a collar contract combined with a put option contract sold by us with a strike price below the floor price of the collar. We receive price protection at the purchased put option floor price of the 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 deltadifference 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.
A swaption gives counterparties the right, but not the obligation, to enter into swap agreements with us on the option expiration dates.
Sold calls are entered into to receive premiums for establishing a maximum price that would be settled for the notional volumes covered by the respective contracts. Sold puts are entered into to receive premiums for establishing a minimum price that would be settled for the notional volumes covered by basis swap contracts.
While these instruments mitigate the cash flow risk of future reductions in commodity prices, they may also curtail benefits during periods of increasing commodity prices.
See Note 14. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of our Additionally, derivative instruments.Counterparty Credit RiskDerivative instruments expose us to counterparty credit risk, especially during periods of falling prices. Our commodity derivative instruments are currently with a diversified group of major banks or market participants. We monitor the creditworthiness of these counterparties and our internal hedge policies provide for exposure limits. 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. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices and could incur a loss.
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Unsettled Commodity Derivative Instruments As of December 31, 2018,2019, we had entered into the following crude oil derivative instruments:
|
| | | | | | | | | | | | | | | | | | | | |
| | | | | | 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 |
| 2019 | Swaps | NYMEX WTI | 22,000 | | $ | — |
| $ | 56.96 |
| | $ | — |
| $ | — |
| $ | — |
|
| 2019 | Three-Way Collars | NYMEX WTI | 33,000 | | — |
| — |
| | 49.35 |
| 59.35 |
| 72.25 |
|
| 2019 | Swaps | ICE Brent | 5,000 | | — |
| 57.00 |
| | — |
| — |
| — |
|
| 2019 | Three-Way Collars | ICE Brent | 3,000 | | — |
| — |
| | 43.00 |
| 50.00 |
| 64.07 |
|
| 2019 | Basis Swaps | (1) | 27,000 | | (3.23 | ) | — |
| | — |
| — |
| — |
|
| 2020 | Swaption | NYMEX WTI | 5,000 | | — |
| 61.79 |
| | — |
| — |
| — |
|
| 2020 | Basis Swap | (1) | 15,000 | | (5.01 | ) | — |
| | — |
| — |
| — |
|
|
| | | | | | | | | | | | | | | | | | | | |
| | | | | | 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 |
| 2020 | Sold Calls | NYMEX WTI | 8,000 | | $ | — |
| $ | 65.59 |
| | $ | — |
| $ | — |
| $ | — |
|
| 2020 | Swaps | NYMEX WTI | 35,000 | | — |
| 58.12 |
| | — |
| — |
| — |
|
| 2020 | Three-Way Collars | NYMEX WTI | 30,000 | | — |
| — |
| | 48.33 |
| 57.87 |
| 64.27 |
|
| Jan2020-Jun2020 | Swaps | NYMEX WTI | 24,000 | | — |
| 59.54 |
| | — |
| — |
| — |
|
| Jul2020-Dec2020 | Call Swaption | NYMEX WTI | 11,000 | | — |
| 58.95 |
| | — |
| — |
| — |
|
| 2020 | Basis Swaps | (1) | 15,000 | | (5.01 | ) | — |
| | — |
| — |
| — |
|
| |
(1) | We have entered into crude oil basis swap contracts in order to fixestablish 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. |
As of December 31, 2019, we had entered into the following NGL derivative instruments: |
| | | | | | | |
| | | | | | Swaps |
| Settlement Period | Type of Contract | Index | Bbls per Day | | Weighted Average Fixed Price |
| Apr 2020-Sept 2020 | Ethane Swaps | Mont Belvieu | 2,000 | | $ | 7.77 |
|
| Apr 2020-Sept 2020 | Propane Swaps | Mont Belvieu | 5,000 | | 21.04 |
|
| Apr 2020-Sept 2020 | Isobutane Swaps | Mont Belvieu | 1,000 | | 25.36 |
|
| Apr 2020-Sept 2020 | Butane Swaps | Mont Belvieu | 1,500 | | 24.31 |
|
As of December 31, 2018,2019, we had entered into the following natural gas derivative instruments:
|
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | Swaps | | Collars |
Settlement Period | 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 |
1Q19(1) | Swaps | NYMEX HH | 86,500 |
| | $ | — |
| $ | 4.36 |
| | $ | — |
| $ | — |
| $ | — |
|
1Q19(1) | Three-Way Collars | NYMEX HH | 21,500 |
| | — |
| — |
| | 3.00 |
| 3.25 |
| 4.08 |
|
| 2019 | Three-Way Collars | NYMEX HH | 104,000 |
| | — |
| — |
| | 2.25 |
| 2.65 |
| 2.95 |
|
| 2019 | Basis Swaps | (2) | 52,000 |
| | (0.74 | ) | — |
| | — |
| — |
| — |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | Swaps | | Collars |
| Settlement Period | 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 |
| Apr2020-Dec2020 | Swaps | NYMEX HH | 90,000 |
| | $ | — |
| $ | 2.60 |
| | $ | — |
| $ | — |
| $ | — |
|
| Apr2020-Oct2020 | Three-Way Collars | NYMEX HH | 40,000 |
| | — |
| — |
| | 2.25 |
| 2.70 |
| 2.85 |
|
| 2020 | Sold Puts | NYMEX HH | 90,000 |
| | — |
| — |
| | 2.15 |
| — |
| — |
|
| 2020 | Basis Swaps | CIG (1) | 139,000 |
| | (0.56 | ) | — |
| | — |
| — |
| — |
|
| 2020 | Basis Swaps | Waha (1) | 49,500 |
| | (1.05 | ) | — |
| | — |
| — |
| — |
|
| 2021 | Basis Swaps | CIG (1) | 60,000 |
| | (0.52 | ) | — |
| | — |
| — |
| — |
|
| 2021 | Basis Swaps | Waha (1) | 14,000 |
| | (0.60 | ) | — |
| | — |
| — |
| — |
|
(1) We have entered into contracts for portions of 2019 resulting in the difference in hedged volumes for the full year.
(2) 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 Amounts and Gains and Losses on Derivative InstrumentsThe fair values of derivative instruments on our consolidated balance sheets were as follows (1):
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Asset Derivative Instruments | | Liability Derivative Instruments |
| | December 31, 2018 | | December 31, 2017 | | December 31, 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 |
Commodity Derivative Instruments | Current Assets | | $ | 180 |
| | Current Assets | | $ | 2 |
| | Current Liabilities | | $ | 1 |
| | Current Liabilities | | $ | 58 |
|
| | Noncurrent Assets | | — |
| | Noncurrent Assets | | — |
| | Noncurrent Liabilities | | 26 |
| | Noncurrent Liabilities | | 15 |
|
| Total | | | $ | 180 |
| | | | $ | 2 |
| | | | $ | 27 |
| | | | $ | 73 |
|
(1) See Note 1. Summary of Significant Accounting Policies – Derivative Instruments and Hedging Activities. | |
(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 (CIG) and Waha Hub versus NYMEX Henry Hub (HH). The weighted average differential represents the amount of reduction to NYMEX HH prices for the notional volumes covered by the basis swap contracts. |
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Fair Value Amounts and Gains and Losses on Derivative InstrumentsThe effectfair values of derivative instruments on our consolidated statements of operations wasbalance sheets were as follows:follows (in millions):
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| (millions) | 2018 | | 2017 | | 2016 |
| Cash Paid (Received) in Settlement of Commodity Derivative Instruments | | | | | |
| Crude Oil | $ | 162 |
| | $ | (14 | ) | | $ | (499 | ) |
| Natural Gas | (1 | ) | | 1 |
| | (70 | ) |
| Total Cash Paid (Received) in Settlement of Commodity Derivative Instruments | 161 |
| | (13 | ) | | (569 | ) |
| Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments | | | | | |
| Crude Oil | (225 | ) | | 18 |
| | 582 |
|
| Natural Gas | 1 |
| | (68 | ) | | 126 |
|
| Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments | (224 | ) | | (50 | ) | | 708 |
|
| (Gain) Loss on Commodity Derivative Instruments | | | | | |
| Crude Oil | (63 | ) | | 4 |
| | 83 |
|
| Natural Gas | — |
| | (67 | ) | | 56 |
|
| Total (Gain) Loss on Commodity Derivative Instruments | $ | (63 | ) | | $ | (63 | ) | | $ | 139 |
|
|
| | | | | | | | | | | | | | | | |
| Asset Derivative Instruments | | Liability Derivative Instruments |
| Balance Sheet Location | December 31, 2019 | | December 31, 2018 | | Balance Sheet Location | December 31, 2019 | | December 31, 2018 |
| Other Current Assets | $ | 14 |
| | $ | 180 |
| | Other Current Liabilities | $ | 36 |
| | $ | 1 |
|
| Other Noncurrent Assets | 1 |
| | — |
| | Other Noncurrent Liabilities | 1 |
| | 26 |
|
| Total Assets | $ | 15 |
| | $ | 180 |
| | Total Liabilities | $ | 37 |
| | $ | 27 |
|
Note 14. 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 on 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 InvestmentsOur mutual fund investments consist of various publicly-traded mutual funds that include investments ranging from equities to money market instruments. The fair values are based on quoted market prices for identical assets.
Commodity Derivative Instruments Our commodity derivative instruments may include variable to fixed price commodity swaps, two-way collars, three-way collars, swaptions, enhanced swaps and basis swaps. We estimate the fair values of these instruments using published forward commodity price curves as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBORLondon Inter-bank Offered Rate (LIBOR) rates, Eurodollar futures rates and interest swap rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. In addition, for collars, we estimate the option values of the put options sold and the contract floors and ceilings using an option pricing model which considers market volatility, market prices and contract terms. See Note 13. Derivative InstrumentsAmounts include the impact of netting clauses within our master agreements that allow us to net cash settle asset and Hedging Activities.liability positions with the same counterparty.Deferred Compensation LiabilityThe value is dependent upon the fair valueseffect of mutual fund investments and sharesderivative instruments on our consolidated statements of our common stock held in a rabbi trust.See Mutual Fund Investments above.
|
| | |
| 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 | | | | |
| (millions) | 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 |
| December 31, 2018 | | | | | | | | | |
| Financial Assets | | | | | | | | | |
| Mutual Fund Investments | $ | 38 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 38 |
|
| Commodity Derivative Instruments | — |
| | 187 |
| | — |
| | (7 | ) | | 180 |
|
| Financial Liabilities | | | | | | | | | |
| Commodity Derivative Instruments | — |
| | (34 | ) | | — |
| | 7 |
| | (27 | ) |
| Portion of Deferred Compensation Liability Measured at Fair Value | (43 | ) | | — |
| | — |
| | — |
| | (43 | ) |
| Stock Based Compensation Liability Measured at Fair Value | (8 | ) | | — |
| | — |
| | — |
| | (8 | ) |
| December 31, 2017 | | | | | | | |
| | |
|
| Financial Assets | |
| | |
| | |
| | |
| | |
|
| Mutual Fund Investments | $ | 57 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 57 |
|
| Commodity Derivative Instruments | — |
| | 7 |
| | — |
| | (5 | ) | | 2 |
|
| Financial Liabilities | | | | | | | | | |
| Commodity Derivative Instruments | — |
| | (78 | ) | | — |
| | 5 |
| | (73 | ) |
| Portion of Deferred Compensation Liability Measured at Fair Value | (71 | ) | | — |
| | — |
| | — |
| | (71 | ) |
| Stock Based Compensation Liability Measured at Fair Value | (10 | ) | | — |
| | — |
| | — |
| | (10 | ) |
| |
(2)
| Amount represents the impact of netting clauses within our master agreements that allow us to net cash settle asset and liability positions with the same counterparty. |
Assets and Liabilities Measured at Fair Value on a Nonrecurring BasisCertain assets and liabilities are measured at fair value on a nonrecurring basis on our consolidated balance sheets. See Note 1. Summary of Significant Accounting Policies for the methods and assumptions used to estimate the fair values:Asset ImpairmentsImpairments are recorded when we determine that the carrying amounts of certain oil and gas properties or midstream facilities are not recoverable from future cash flows, and are calculated using significant unobservable (Level 3) inputs. In 2018, upon classification of the Gulf of Mexico properties as assets held for sale, we recognized impairment expense of $168 million. Additionally, in fourth quarter 2018, we recorded impairment expense of $38 million, $37 million of which related to changes in construction plans for certain midstream assets.
The 2017 impairment of $70 million primarily related to our decision not to pursue development of the Troubadour natural gas discovery in the Gulf of Mexico. The 2016 impairment of $92 million primarily related to a decision to write off certain development concepts associated with the Leviathan natural gas project that were not selected. The assets were reduced to their estimated fair values.
Inventory Impairment In 2016, we determined that the carrying amount of certain of our materials and supplies inventory was greater than its net realizable value, which was calculated using significant unobservable (Level 3) inputs. We recognized a $14 million impairment related to these assets.
Goodwill ImpairmentIn fourth quarter 2018, we determined that the carrying amount of goodwill allocated to our Texas reporting unit was less than its estimated fair value, which was calculated using significant unobservable (Level 3) inputs. As a result, we recognized a goodwill impairment of $1.3 billion. See Note 6. Goodwill Impairment.Marcellus Shale Firm Transportation Liability In 2017, we recorded liabilities totaling $93 million representing the discounted present value of our remaining obligation under certain firm transportation contracts. See Note 10. Marcellus Shale Firm Transportation Commitments.
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Additional Fair Value Disclosures
Debt The fair value of fixed-rate, public debt is estimated based on the published market prices for the same or similar issues. As such, we consider the fair value of our public, fixed-rate debt to be a Level 1 measurement on the fair value hierarchy.
At December 31, 2018, our variable-rate, non-public debt included the Revolving Credit Facility, Noble Midstream Services Revolving Credit Facility and the Noble Midstream Services Term Loan Credit Facility. The fair value is estimated based on significant other observable inputs. As such, we consider the fair value of these facilities to be a Level 2 measurement on the fair value hierarchy. See Note 9. Long-Term Debt.Fair value information regarding our debt is as follows: |
| | | | | | | | | | | | | | | |
| | December 31, 2018 | | December 31, 2017 |
| (millions) | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
Long-Term Debt, Net (1) | $ | 6,452 |
| | $ | 6,121 |
| | $ | 6,586 |
| | $ | 7,142 |
|
(1)Excludes unamortized discount, premium, debt issuance costs and capital lease obligations.
Note 15. Equity Method Investments
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; and
28% interest in Alba Plant , which owns and operates a LPG processing plant in Equatorial Guinea.
We consider these equity method investments essential components of our business as well as necessary and integral elements of our value chain in support of ongoing operations in our Midstream and West Africa segments. For the Advantage Pipeline system, Noble Midstream Partners serves as operator and exerts significant influence over the day-to-day operations. The operating agreements for Advantage Pipeline empower the board to direct activities that most significantly affect long-term economic performance. With regard to AMPCO, we hold a voting position on AMPCO's leadership team through AMPCO's management committee, and our asset teams influence decisions regarding capital investments, budgets, turnarounds, maintenance and other project matters. For the Alba Plant, our Alba asset teams are fully engaged in operational and financial decisions and exert significant influence in the monetization of the Alba field and Alba Plant.
Equity method investments are as follows: |
| | | | | | | | |
| | | December 31, |
| (millions) | | 2018 | | 2017 |
| Advantage Pipeline | | $ | 73 |
| | $ | 70 |
|
| AMPCO | | 131 |
| | 129 |
|
| Alba Plant | | 58 |
| | 80 |
|
| Other | | 24 |
| | 26 |
|
| Total Equity Method Investments | | $ | 286 |
| | $ | 305 |
|
Additional Information At December 31, 2018, consolidated retained earnings included $68 million related to the undistributed earnings of equity method investees.
The carrying value of our AMPCO investment was $13 million higher than the underlying net assets of the investee at December 31, 2018. The difference is related to capitalized interest which is being amortized into earnings over the remaining useful life of the plant.
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Summarized, 100% combined financial information for equity method investees is as follows: |
| | | | | | | | |
| | | December 31, |
| (millions) | | 2018 | | 2017 |
| Balance Sheet Information | | | | |
| Current Assets | | $ | 387 |
| | $ | 390 |
|
| Noncurrent Assets | | 575 |
| | 588 |
|
| Current Liabilities | | 198 |
| | 171 |
|
| Noncurrent Liabilities | | 81 |
| | 90 |
|
|
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| (millions) | | 2018 | | 2017 | | 2016 |
| Statements of Operations Information | | | | | | |
| Operating Revenues | | $ | 855 |
| | $ | 790 |
| | $ | 667 |
|
| Operating Expenses | | 284 |
| | 303 |
| | 355 |
|
| Operating Income | | 571 |
| | 487 |
| | 312 |
|
| Other Income, net | | 3 |
| | 15 |
| | 7 |
|
| Income Before Income Taxes | | 574 |
| | 502 |
| | 319 |
|
| Income Tax Provision | | 152 |
| | 136 |
| | 60 |
|
| Net Income | | $ | 422 |
| | $ | 366 |
| | $ | 259 |
|
Note 16.15. Additional Shareholders’ Equity Information
Common Stock and Treasury Stock Activity in shares of our common stock and treasury stock was as follows: | | | | | Year Ended December 31, | Year Ended December 31, |
| | | 2018 | | 2017 | 2019 | | 2018 |
| Shares of Common Stock Issued | | |
| | |
| |
| | |
|
| Shares, Beginning of Period | | 528,743,381 |
| | 471,360,427 |
| 521,055,001 |
| | 528,743,381 |
|
| Exercise of Common Stock Options | | 576,617 |
| | 382,882 |
| — |
| | 576,617 |
|
Restricted Stock Awarded, Net of Forfeitures (1) | | 2,488,363 |
| | 2,912,936 |
| 2,768,731 |
| | 2,488,363 |
|
Purchase and Retirement of Common Stock (2)(1) | | (10,008,128 | ) | | — |
| — |
| | (10,008,128 | ) |
| Shares Exchanged in Clayton Williams Energy Acquisition | | (745,232 | ) | | 54,087,136 |
| |
| Adjustment to Shares Exchanged in Clayton Williams Energy Acquisition | | — |
| | (745,232 | ) |
| Shares, End of Period | | 521,055,001 |
| | 528,743,381 |
| 523,823,732 |
| | 521,055,001 |
|
| Treasury Stock | | | | | | | |
| Shares, Beginning of Period | | 38,786,969 |
| | 37,961,316 |
| 38,851,988 |
| | 38,786,969 |
|
Shares Received in Payment of Withholding Taxes Due on Vesting of Shares of Restricted Stock (3) | | 267,258 |
| | 1,026,891 |
| 240,865 |
| | 267,258 |
|
| Rabbi Trust Shares Distributed and/or Sold | | (202,239 | ) | | (201,238 | ) | (203,063 | ) | | (202,239 | ) |
| Shares, End of Period | | 38,851,988 |
| | 38,786,969 |
| 38,889,790 |
| | 38,851,988 |
|
| Additional Information | | | | | | | |
| Incremental Shares From Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust | | — |
| | — |
| — |
| | — |
|
Number of Antidilutive Stock Options, Shares of Restricted Stock and Shares of Common Stock in Rabbi Trust excluded from Dilutive Earnings (Loss) per Share (4)(2) | | 15,004,591 |
| | 15,619,276 |
| 13,892,742 |
| | 15,004,591 |
|
| |
(1) | The 2017 amount includes approximately 1.9 million shares of restricted stock awarded to former holders of Clayton Williams Energy outstanding stock awards as part of the Clayton Williams Energy Acquisition. |
| |
(2)
| On February 15, 2018, we announced that the Company's Board of Directors had authorized a share repurchase program of $750 million which expires December 31, 2020. TheseIn 2019, no shares were repurchased and retired. In 2018, shares were repurchased and retired at an average price of $29.49 per share. |
| |
(3)
| The 2017 amount includes approximately 720,000 shares of common stock received from Clayton Williams Energy shareholders for the payment of withholding taxes due on the vesting of Clayton Williams Energy restricted shares and options pursuant to the purchase and sale agreement. |
| |
(4)(2)
| For the years ended December 31, 20182019 and 2017,2018, all outstanding options and non-vested restricted shares have been excluded from the calculation of diluted earnings (loss) per share as Noble Energy incurred a loss. Therefore, inclusion of outstanding options and non-vested restricted shares in the calculation of diluted earnings (loss) per share would be anti-dilutive. |
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Accumulated Other Comprehensive Loss (AOCL) AOCL in the shareholders’ equity section of the balance sheet included: | | | (millions) | | Interest Rate Cash Flow Hedge | | Other Postretirement Benefit Plans | | Total | Interest Rate Cash Flow Hedge | | Other Postretirement Benefit Plans | | Total |
| December 31, 2015 | | $ | (22 | ) | | $ | (11 | ) | | $ | (33 | ) | |
| Realized Amounts Reclassified Into Earnings | | 1 |
| | 4 |
| | 5 |
| |
| Unrealized Change in Fair Value | | — |
| | (3 | ) | | (3 | ) | |
| December 31, 2016 | | (21 | ) | | (10 | ) | | (31 | ) | $ | (21 | ) | | $ | (10 | ) | | $ | (31 | ) |
| Realized Amounts Reclassified Into Earnings | | 1 |
| | 4 |
| | 5 |
| 1 |
| | 4 |
| | 5 |
|
| Unrealized Change in Fair Value | | — |
| | (4 | ) | | (4 | ) | — |
| | (4 | ) | | (4 | ) |
| December 31, 2017 | | (20 | ) | | (10 | ) | | (30 | ) | (20 | ) | | (10 | ) | | (30 | ) |
| Realized Amounts Reclassified Into Earnings | | (3 | ) | | 1 |
| | (2 | ) | (3 | ) | | 1 |
| | (2 | ) |
| Unrealized Change in Fair Value | | — |
| | — |
| | — |
| |
| December 31, 2018 | | $ | (23 | ) | | $ | (9 | ) | | $ | (32 | ) | (23 | ) | | (9 | ) | | (32 | ) |
| Realized Amounts Reclassified Into Earnings | | 1 |
| | — |
| | 1 |
|
| December 31, 2019 | | $ | (22 | ) | | $ | (9 | ) | | $ | (31 | ) |
Items in AOCL were initially recorded net of tax, using an effective income tax rate of 35%. In fourth quarter 2018, we reclassified to retained earnings approximately $6 million representing the effect of the decrease in the income tax rate to 21%.
AOCL at December 31, 20182019 included deferred losses of $24$22 million, net of tax, related to an interest rate derivative instrument. This amount is reclassified to earnings as an adjustment to interest expense over the term of our senior notes due March 2041.
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Note 17.16. Stock-Based and Other Compensation Plans
We recognized total stock-based compensation expense as follows: | | | | | Year Ended December 31, | Year Ended December 31, |
| (millions) | | 2018 | | 2017 | | 2016 | 2019 | | 2018 | | 2017 |
| Stock-Based Compensation Expense Included in: | | | | | | | |
| General and Administrative Expense | | $ | 54 |
| | $ | 56 |
| | $ | 62 |
| $ | 59 |
| | $ | 54 |
| | $ | 56 |
|
| Exploration Expense and Other | | 8 |
| | 48 |
| | 15 |
| 9 |
| | 8 |
| | 48 |
|
| Total Stock-Based Compensation Expense | | $ | 62 |
| | $ | 104 |
| | $ | 77 |
| |
Total Stock-Based Compensation Expense (1) | | $ | 68 |
| | $ | 62 |
| | $ | 104 |
|
| Tax Benefit Recognized | | $ | (13 | ) | | $ | (36 | ) | | $ | (27 | ) | $ | (14 | ) | | $ | (13 | ) | | $ | (36 | ) |
| |
(1) | 2019 amount excludes $8 million capitalized to property, plant and equipment. |
Stock Option and Restricted Stock Plans Our stock option and restricted stock plans are described below.
2017 Long-Term Incentive Plan On April 25, 2017, our shareholders approved the Noble Energy, Inc. 2017 Long-Term Incentive Plan (the 2017 Plan). Upon shareholder approval, the 2017 Plan superseded and replaced the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan, as amended (the 1992 Plan) which was frozen so that no future grants would be made under the 1992 Plan. The 1992 Plan continues to govern awards that were outstanding as of the date of its suspension, which remain in effect pursuant to their terms. Under the 2017 Plan, the Compensation, Benefits and Stock Option Committee of the Board of Directors (the Committee) may grant stock options, stock appreciation rights, restricted stock, restricted stock units, performance awards, stock awards and other incentive awards to our officers or other employees and those of our subsidiaries. The maximum number of shares that may be granted under the 2017 Plan is 2944 million shares of common stock. At December 31, 2018, 26,621,6322019, 39,693,735 shares of our common stock were reserved for issuance, including 21,084,92828,407,839 shares available for future grants and awards, under the 2017 Plan.
Stock options are issued with an exercise price equal to the fair market value of our common stock on the date of grant, and are subject to such other terms and conditions as may be determined by the Committee. Unless granted by the Committee for a shorter term, the options expire 10 years from the grant date. Option grants generally vest ratably over a three-year period.
Restricted stock awards made under the 2017 Plan are subject to such restrictions, terms and conditions, including forfeitures, if any, as may be determined by the Committee. During the period in which such restrictions apply, unless specifically provided otherwise in accordance with the terms of the 2017 Plan, the recipient of restricted stock would be the record owner of the shares and have all the rights of a shareholder with respect to the shares, including the right to vote and the right to receive dividends or other distributions made or paid with respect to the shares. The dividends or other distributions pertaining to the restricted shares will be held by the Company until the restriction period ends and the shares vest or forfeit. If the restricted shares forfeit, then the recipient shall not be entitled to receive the dividend or distribution, which will transfer to the Company.
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Restricted stock awards with a time-vested restriction vest over a two or three-year period. Performance share awards cliff vest after a three-year period if the Company achieves certain levels of total shareholder return relative to a pre-determined industry peer group.
2015 Stock Plan for Non-Employee Directors The 2015 Stock Plan for Non-Employee Directors of Noble Energy, Inc., as amended (the 2015 Plan) provides for grants of stock options and awards of restricted stock to our non-employee directors. The 2015 Plan superseded and replaced the 2005 Stock Plan for Non-Employee Directors of Noble Energy, Inc. The total number of shares of our common stock that may be issued under the 2015 Plan is 708,996. At December 31, 2018, 576,7982019, 485,062 shares of our common stock were reserved for issuance, including 397,979306,243 shares available for future grants and awards, under the 2015 Plan.
Stock Option Grants The fair value of each stock option granted is estimated on the date of grant using a Black-Scholes-Merton option valuation model that used the assumptions described below:
| |
| • | Expected term The expected term representsRepresents 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 representsRepresents 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. |
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
| |
| • | Risk-free rate The risk-free rate isRepresents the implied yield available on US Treasury securities with a remaining term equal to the expected term of the option. We base our risk-free rate on a weighting of five and seven year US Treasury securities as of the date of grant. |
| |
| • | Dividend yield The dividend yield representsRepresents 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: | | | | | Year Ended December 31, | Year Ended December 31, |
| (weighted averages) | | 2018 | | 2017 | | 2016 | 2019 | | 2018 | | 2017 |
| Expected Term (in Years) | | 6.7 |
| | 6.4 |
| | 6.3 |
| 6.9 |
| | 6.7 |
| | 6.4 |
|
| Expected Volatility | | 33.4 | % | | 33.2 | % | | 32.4 | % | 33.8 | % | | 33.4 | % | | 33.2 | % |
| Risk-Free Rate | | 2.6 | % | | 2.2 | % | | 1.6 | % | 2.7 | % | | 2.6 | % | | 2.2 | % |
| Expected Dividend Yield | | 1.2 | % | | 0.9 | % | | 0.7 | % | 1.4 | % | | 1.2 | % | | 0.9 | % |
| Weighted Average Grant-Date Fair Value | | $ | 10.47 |
| | $ | 13.26 |
| | $ | 10.10 |
| $ | 7.57 |
| | $ | 10.47 |
| | $ | 13.26 |
|
Stock option activity was as follows: | | | | | Options | | Weighted Average Exercise Price | | Weighted Average Remaining Contractual Term | | Aggregate Intrinsic Value | Options | | Weighted Average Exercise Price | | Weighted Average Remaining Contractual Term | | Aggregate Intrinsic Value |
| | | | | (per share) | | (in years) | | (in millions) | | | (per share) | | (years) | | (millions) |
| Outstanding at December 31, 2017 | | 15,549,222 |
| | $ | 43.42 |
| | | |
| Outstanding at December 31, 2018 | | 13,852,020 |
| | $ | 44.04 |
| | |
| Granted | | 551,888 |
| | 30.20 |
| | | 461,311 |
| | 22.15 |
| | |
| Exercised | | (576,617 | ) | | 34.55 |
| | | |
| Forfeited | | (1,672,473 | ) | | 40.04 |
| | | (51,100 | ) | | 34.72 |
| | |
| Outstanding at December 31, 2018 | | 13,852,020 |
| | $ | 44.04 |
| | 5.0 | | $ | — |
| |
| Exercisable at December 31, 2018 | | 11,866,188 |
| | $ | 45.58 |
| | 4.0 | | $ | — |
| |
| Expired | | (1,686,478 | ) | | 35.26 |
| | |
| Outstanding at December 31, 2019 | | 12,575,753 |
| | $ | 44.62 |
| | 4.2 | | $ | 1 |
|
| Exercisable at December 31, 2019 | | 11,373,846 |
| | $ | 46.11 |
| | 3.7 | | $ | — |
|
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
There were no options exercised in 2019. The total intrinsic value of options exercised was $5 million in 2018 and $4 million in 2017 and $10 million in 2016.2017. As of December 31, 2018, $112019, $5 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 1.2 years. We issue new shares of our common stock to settle option exercises. Dividends are not paid on unexercised options.
Restricted Stock Awards Awards of time-vested restricted stock (shares subject to service conditions) are valued at the price of our common stock at the date of award. The fair value of the market based restricted stock awards was estimated on the date of award using a Monte Carlo valuation model that uses the assumptions in the following table. The Monte Carlo valuation model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility represents the extent to which our stock price is expected to fluctuate between now and the award’s anticipated term. We use the historical volatility of Noble Energy common stock for the three-year period ended prior to the date of award. The risk-free rate is based on a three-year period for US Treasury securities as of the year ended prior to the date of award.
The assumptions used in valuing market based restricted stock awards granted were as follows: | | | | Year Ended December 31, | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 | 2019 | | 2018 | | 2017 |
| Number of Simulations | 10,000,000 |
| | 500,000 |
| | 500,000 |
| 10,000,000 |
| | 10,000,000 |
| | 500,000 |
|
| Expected Volatility | 35 | % | | 35 | % | | 38 | % | 37.5 | % | | 35.0 | % | | 35.0 | % |
| Risk-Free Rate | 2.3 | % | | 1.5 | % | | 1.0 | % | 2.5 | % | | 2.3 | % | | 1.5 | % |
Restricted stock activity was as follows: |
| | | | | | | | | | | | | | |
| | | Subject to Time Vesting | | Subject to Market Conditions |
| | | Number of Shares | | Weighted Average Award Date Fair Value | | Number of Shares | | Weighted Average Award Date Fair Value |
| | | | | (per share) | | | | (per share) |
| Outstanding at December 31, 2017 | | 1,839,737 |
| | $ | 37.21 |
| | 1,212,705 |
| | $ | 25.55 |
|
| Awarded | | 2,702,426 |
| | 30.68 |
| | 874,960 |
| | 19.56 |
|
| Vested | | (982,280 | ) | | 35.28 |
| | — |
| | — |
|
| Forfeited | | (386,992 | ) | | 32.65 |
| | (702,031 | ) | | 25.52 |
|
| Outstanding at December 31, 2018 | | 3,172,891 |
| | $ | 32.72 |
| | 1,385,634 |
| | $ | 21.74 |
|
The total fair value of restricted stock that vested was $29 million in 2018, $34 million in 2017, and $24 million in 2016.
The weighted average award-date fair value of restricted stock awarded was $27.96 per share in 2018, $35.45 per share in 2017, and $29.99 per share in 2016.
As of December 31, 2018, $74 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 1.5 years. Common stock dividends accrue on restricted stock awards and are paid upon vesting. We issue new shares of our common stock when awarding restricted stock.
Cash-Settled AwardsOn February 1, 2016, we issued cash-settled awards to certain employees under the 1992 Plan in lieu of a portion of restricted stock and stock options. We issued approximately one million awards (so called phantom units, the nomenclature used in accounting literature), a portion of which are subject to the Company's achievement of certain levels of total shareholder return relative to a pre-determined industry peer group. The fair value of the market based phantom unit awards was estimated on the date of award using a Monte Carlo valuation model and assumed 500,000 simulations, 38% expected volatility and a risk-free rate of 0.9%.
These phantom units represent a hypothetical interest in the Company, and, once vested, are settled in cash. The phantom unit value at vesting will equal the lesser of the fair market value of a share of common stock of the Company as of the vesting date (two-year cliff vesting for officers and three-year cliff vesting for non-officers) or up to four times the fair market value of a share of common stock of the Company, which was $31.65, as of the grant date.
We accrued a liability of $8 million in 2018 related to the phantom units. No phantom units were awarded in 2018 or 2017.
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Phantom unitRestricted stock activity was as follows: | | | | | Subject to Time Vesting | | Subject to Market Conditions | Subject to Time Vesting | | Subject to Market Conditions |
| | | Number of Units | | Weighted
Average
Award Date
Fair Value | | Number of Units | | Weighted Average Award Date Fair Value | Number of Shares | | Weighted Average Award Date Fair Value | | Number of Shares | | Weighted Average Award Date Fair Value |
| | | | | (per share) | | | | (per share) | | | (per share) | | | | (per share) |
| Outstanding at December 31, 2017 | | 610,159 |
| | $ | 31.65 |
| | 167,483 |
| | $ | 6.82 |
| |
| Outstanding at December 31, 2018 | | 3,172,891 |
| | $ | 32.72 |
| | 1,385,634 |
| | $ | 21.74 |
|
| Awarded | | 2,464,682 |
| | 22.33 |
| | 1,138,730 |
| | 13.50 |
|
| Vested | | (83,276 | ) | | 31.65 |
| | — |
| | — |
| (906,485 | ) | | 34.11 |
| | — |
| | — |
|
| Forfeited | | (59,518 | ) | | 31.65 |
| | (17,187 | ) | | 6.82 |
| (486,733 | ) | | 27.97 |
| | (347,948 | ) | | 21.20 |
|
| Outstanding at December 31, 2018 | | 467,365 |
| | $ | 31.65 |
| | 150,296 |
| | $ | 6.82 |
| |
| Outstanding at December 31, 2019 | | 4,244,355 |
| | $ | 27.02 |
| | 2,176,416 |
| | $ | 17.52 |
|
The total fair value of restricted stock that vested was $20 million in 2019, $29 million in 2018, and $34 million in 2017. The weighted average award-date fair value per share of restricted stock awarded was $19.54 in 2019, $27.96 in 2018, and $35.45 in 2017.
As of December 31, 2018,2019, $74 million of compensation cost related to phantom unitsall of our unvested restricted stock awarded under the Plans remained to be recognized was de minimis.recognized. The remaining cost is expected to be recognized in first quarter 2019. The total fair valueover a weighted-average period of 1.4 years. Common stock dividends accrue on restricted stock awards and are paid upon vesting. We issue new shares of our common stock when awarding restricted stock.
Cash-Settled AwardsPeriodically, we issue cash-settled awards (so called phantom units, thatthe nomenclature used in accounting literature) to certain employees in lieu of a portion of restricted stock and stock options. These phantom units represented a hypothetical interest in the Company and, once vested, are settled in 2018 was de minimis.cash. Common stock dividends accrue on phantom units and are paid upon vesting.
On February 1, 2016, we issued 1000000 phantom units under the 1992 Plan, a portion of which were subject to the Company's achievement of certain levels of total shareholder return relative to a pre-determined industry peer group. The phantom units vested during 2019 at $31.65 per share which was equal to the grant date fair value. The fair value of the market based phantom unit awards was estimated on the date of award using a Monte Carlo valuation model and assumed 500,000 simulations, 38% expected volatility and a risk-free rate of 0.9%. These awards vested at 0% as performance was not achieved.
On February 19, 2019, we issued 803,606 phantom units under the 2017 Plan. The units had a grant date fair value of $22.39 and vest ratably over three years. The value at vesting will equal the fair market value of a share of common stock of the Company as of the vesting date.
Phantom unit activity was as follows: |
| | | | | | | | | | | | | |
| | Subject to Time Vesting | | Subject to Market Conditions |
| | Number of Units | | Weighted Average Award Date Fair Value | | Number of Units | | Weighted Average Award Date Fair Value |
| | | | (per share) | | | | (per share) |
| Outstanding at December 31, 2018 | 467,365 |
| | $ | 31.65 |
| | 150,296 |
| | $ | 6.82 |
|
| Awarded | 803,606 |
| | 22.39 |
| | — |
| | — |
|
| Vested | (462,823 | ) | | 31.65 |
| | — |
| | — |
|
| Forfeited | (92,762 | ) | | 22.55 |
| | (150,296 | ) | | 6.82 |
|
| Outstanding at December 31, 2019 | 715,386 |
| | $ | 22.39 |
| | — |
| | $ | — |
|
As of December 31, 2019, $11 million of compensation cost related to phantom units remained to be recognized. The cost is expected to be recognized over a weighted-average period of 2.1 years. The total fair value of phantom units that vested in 2019 was $10 million. We accrued a liability of $5 million in 2019 related to the phantom units.
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| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
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 $32 million in 2019, $31 million in 2018 and $31 million in 2017, and $32 million in 2016.2017.
Deferred Compensation PlanPlans We have a non-qualified deferred compensation plan for which participant-directed investments are held in a rabbi trust and are available to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Participants in that nonqualified deferred compensation plan may elect to receive distributions in either cash or shares of our common stock. Components of thatAssets within the rabbi trust are as follows: |
| | | | | | | | |
| | | December 31, |
| (millions, except share amounts) | | 2018 | | 2017 |
| Mutual Fund Investments | | $ | 38 |
| | $ | 57 |
|
| Noble Energy Common Stock (at Fair Value) | | 5 |
| | 14 |
|
| Total Rabbi Trust Assets | | $ | 43 |
| | $ | 71 |
|
| Liability Under Related Deferred Compensation Plan | | $ | 43 |
| | $ | 71 |
|
| Number of Shares of Noble Energy Common Stock Held by Rabbi Trust | | 267,792 |
| | 470,030 |
|
Assetsprimarily consist of that rabbi trust, other than our common stock, are invested in certainmutual fund investments, which include various publicly-traded mutual funds that, cover an investment spectrumin turn, include investments ranging from equities to money market instruments. These mutual funds have publishedinstruments and totaled $27 million at December 31, 2019. The fair values are based on quoted market prices and are reported atfor identical assets.
The liability associated with the deferred compensation plan, which is dependent upon the fair
value. See Note 14. Fair Value Measurements and Disclosures. The mutual funds are included invalues of the mutual fund investments account in other noncurrent assetsand common stock held in the consolidated balance sheets. Sharesrabbi trust, was $29 million and $43 million at December 31, 2019 and 2018, respectively. The rabbi trust included 64,729 and 267,792 shares of our common stock held by the rabbi trust holding common stockat December 31, 2019 and 2018, respectively, which are accounted for as treasury stock (recorded at cost, $16.72 per share) in the shareholders’ equity section of the consolidated balance sheets. Amounts payable to plan participants are included in other noncurrent liabilities in the consolidated balance sheets and include the market value of the shares of our common stock.
Approximately 200,000 shares, or 75%, of our common stock held in respect of one nonqualified deferred compensation plan at December 31, 2018 were attributable to a member of our Board of Directors. The remaining shares will be distributed in 2019. Distributions of 200,000 shares were made in each of 2019, 2018 and 2017 and 2016. In addition, plan participants sold 2,239 shares of our common stock in 2018, 1,238 shares in 2017, and 1,009 shares in 2016. Proceeds were invested in mutual funds and/or distributed to plan participants. Distributions to plan participants were valued at $23 million in 2019, $18 million in 2018 and $21 million in 2017 and $22 million in 2016. 2017.
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 $9 million in 2019, $2 million in 2018 and $9 million in 2017 and $11 million in 2016.
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
We also maintain other nonqualified deferred compensation plans for the benefit of certain of our employees. Deferred compensation liabilities ofunder these plans were $99 million and $104 million and $116 million were outstanding at December 31, 2019 and 2018, and 2017, respectively, under those other plans.respectively.
|
| | |
| Noble Energy, Inc. | |
| Supplemental Oil and Gas Information | |
| | (Unaudited) | |
In accordance with US GAAP for disclosures about oil and gas producing activities, and SECSecurities and Exchange Commission (SEC) rules for oil and gas reporting disclosures, we are making the following disclosures about our crude oil, NGL and natural gas reserves and exploration and production activities. The results of operations, costs incurred and capitalized costs associated with our Midstream reportable segment are not included in this disclosure.
Reserves There are numerous uncertainties inherent in estimating quantities of proved crude oil, NGL and natural gas reserves and reserves engineering is a subjective process of estimating underground accumulations of crude oil, NGLs 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, NGLNGLs and natural gas that are ultimately recovered.
Economic producibility of reserves is dependent on the crude oil, NGL and natural gascommodity prices used in the reserves estimate. We based our December 31, 2018, 2017, and 2016 reserves estimates on 12-month average commodity prices, unless contractual arrangements designate the price to be used, in accordance with SEC rules. However, commodity prices are volatile and declines in crude oil, NGL and natural gas prices could result in negative reserves revisions. Production, development and abandonment costs are based on year-endyear end economic conditions; therefore increases in these costs could also result in negative reserves revisions. Alternatively, decreases in these costs could result in positive reserves revisions.
Reserves Estimates Estimates of our proved reserves and associated future net cash flows are made solely by our engineers and are the responsibility of management. In accordance with US GAAP, we disclose a standardized measure of discounted future net cash flows related to our proved reserves. In order to standardize the measure, all companies are required to use a 10% discount rate and SEC pricing rules. This prescribed calculation can result in some proved undeveloped reserves (PUDs) having negative present worth, meaning that while these PUDs have positive cash flows, the rate of return is lower than 10%. As of December 31, 2019, we had 4 MMBoe of PUDs, or less than 1% of PUDs, with a negative present worth when discounted at 10%. For additional information regarding our reserves estimation process and internal controls see Items 1. and 2. Business and Properties – Internal Controls Over Reserves Estimates and– Technologies Used in Reserves Estimation. 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, NGLs and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to produce the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
Developed Oil and Gas Reserves Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.
Undeveloped Oil and Gas Reserves PUDs are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.
For complete definitions of proved reserves, refer to SEC Regulation S-X, Rule 4-10(a)(6), (22) and (31).
|
| | |
| Noble Energy, Inc. | |
| Supplemental Oil and Gas Information | |
| | (Unaudited) | |
Proved Oil Reserves (Unaudited) The following reserves schedule was developed by our qualified petroleum engineers and sets forth the changes in estimated quantities of proved crude oil reserves: | | | | | Crude Oil and Condensate (MMBbls) | | Crude Oil and Condensate |
| | | United States | | Equatorial Guinea | | Israel | | Total | |
| Proved Reserves as of: | | | | | | | | | |
| December 31, 2015 | | 256 |
| | 48 |
| | 3 |
| | 307 |
| |
| Revisions of Previous Estimates | | 14 |
| | (4 | ) | | — |
| | 10 |
| |
| Extensions, Discoveries and Other Additions | | 66 |
| | — |
| | — |
| | 66 |
| |
| Sale of Minerals in Place | | (4 | ) | | — |
| | — |
| | (4 | ) | |
| Production | | (36 | ) | | (10 | ) | | — |
| | (46 | ) | |
| (MMBbls) | | | United States | | Equatorial Guinea | | Israel | | Total |
| December 31, 2016 | | 296 |
| | 34 |
| | 3 |
| | 333 |
| | 296 |
| | 34 |
| | 3 |
| | 333 |
|
| Revisions of Previous Estimates | | 29 |
| | 2 |
| | — |
| | 31 |
| |
| Price Revisions | | | 12 |
| | 2 |
| | — |
| | 14 |
|
| Non-Price Revisions | | | 17 |
| | — |
| | — |
| | 17 |
|
| Extensions, Discoveries and Other Additions | | 104 |
| | — |
| | 6 |
| | 110 |
| | 104 |
| | — |
| | 6 |
| | 110 |
|
| Purchase of Minerals in Place | | 43 |
| | — |
| | — |
| | 43 |
| | 43 |
| | — |
| | — |
| | 43 |
|
| Sale of Minerals in Place | | (12 | ) | | — |
| | — |
| | (12 | ) | | (12 | ) | | — |
| | — |
| | (12 | ) |
| Production | | (41 | ) | | (7 | ) | | — |
| | (48 | ) | | (41 | ) | | (7 | ) | | — |
| | (48 | ) |
| December 31, 2017 | | 419 |
| | 29 |
| | 9 |
| | 457 |
| | 419 |
| | 29 |
| | 9 |
| | 457 |
|
| Revisions of Previous Estimates | | (31 | ) | | 3 |
| | — |
| | (28 | ) | |
| Price Revisions | | | 10 |
| | 4 |
| | — |
| | 14 |
|
| Non-Price Revisions | | | (41 | ) | | (1 | ) | | — |
| | (42 | ) |
| Extensions, Discoveries and Other Additions | | 98 |
| | 3 |
| | — |
| | 101 |
| | 98 |
| | 3 |
| | — |
| | 101 |
|
| Sale of Minerals in Place | | (24 | ) | | — |
| | (1 | ) | | (25 | ) | | (24 | ) | | — |
| | (1 | ) | | (25 | ) |
| Production | | (42 | ) | | (6 | ) | | — |
| | (48 | ) | | (42 | ) | | (6 | ) | | — |
| | (48 | ) |
| December 31, 2018 | | 420 |
| | 29 |
| | 8 |
| | 457 |
| | 420 |
| | 29 |
| | 8 |
| | 457 |
|
| Price Revisions | | | (27 | ) | | (1 | ) | | — |
| | (28 | ) |
| Non-Price Revisions | | | (44 | ) | | 3 |
| | — |
| | (41 | ) |
| Extensions, Discoveries and Other Additions | | | 74 |
| | 1 |
| | 1 |
| | 76 |
|
| Sale of Minerals in Place | | | (2 | ) | | — |
| | — |
| | (2 | ) |
| Production | | | (44 | ) | | (5 | ) | | — |
| | (49 | ) |
| December 31, 2019 | | | 377 |
| | 27 |
| | 9 |
| | 413 |
|
| Proved Developed Reserves as of: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| December 31, 2015 | | 137 |
| | 34 |
| | 3 |
| | 174 |
| |
| December 31, 2016 | | 138 |
| | 34 |
| | 3 |
| | 175 |
| | 138 |
| | 34 |
| | 3 |
| | 175 |
|
| December 31, 2017 | | 176 |
| | 29 |
| | 3 |
| | 208 |
| | 176 |
| | 29 |
| | 3 |
| | 208 |
|
| December 31, 2018 | | 165 |
| | 26 |
| | 2 |
| | 193 |
| | 165 |
| | 26 |
| | 2 |
| | 193 |
|
| December 31, 2019 | | | 176 |
| | 25 |
| | 9 |
| | 210 |
|
| Proved Undeveloped Reserves as of: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| December 31, 2015 | | 119 |
| | 14 |
| | — |
| | 133 |
| |
| December 31, 2016 | | 158 |
| | — |
| | — |
| | 158 |
| | 158 |
| | — |
| | — |
| | 158 |
|
| December 31, 2017 | | 243 |
| | — |
| | 6 |
| | 249 |
| | 243 |
| | — |
| | 6 |
| | 249 |
|
| December 31, 2018 | | 255 |
| | 3 |
| | 6 |
| | 264 |
| | 255 |
| | 3 |
| | 6 |
| | 264 |
|
| December 31, 2019 | | | 201 |
| | 2 |
| | — |
| | 203 |
|
Revisions of Previous Estimates Oil revisions included:
Price Revisions
| |
◦ | 2016 positive price revisions included 19 MMBbls in the US and 4 MMBbls in Equatorial Guinea. |
| |
◦ | 2017 positive price revisions included 12 MMBbls in the US. |
| |
◦ | 2018 positive price revisions of 14 MMBbls included 10 MMBbls in the US and 4 MMBbls in Equatorial Guinea. |
Non-Price Revisions
| |
◦ | 2016 US2017 revisions associated with positive performance and/or decreases in development or operating costs included revisions of 33 MMBbls in the DJ Basin, Marcellus Shale, Delaware Basin and Gulf of Mexico. |
| |
◦ | 2017 US revisions associated with positive performance totaled 17 MMBbls, of which 14 were primarily attributable to the Delaware Basin due to continued optimization of well development and improved producing well performance. |
| |
◦ | 2018 includes negative non-price revisions of 42 MMBbls, which primarily includes 30 MMBbls for changes in expected recoveries and increased operating and capital costs in the Delaware Basin, and 11 MMBbls for changes in the previously adopted development plan in the Eagle Ford Shale and DJ Basin. |
2019 revisions included a 41 MMBbls revision (29 MMBbls of PUDs and 12 MMBbls of proved developed) in the Delaware Basin for changes in development plans and performance.
Extensions, Discoveries and Other Additions
2017 included additions of 59 MMBbls and 42 MMBbls in the Delaware and DJ Basins, respectively, primarily due to the addition of planned new locations and activity.
2018 extensions relate to drilling plans for new wells and primarily include 55 MMBbls and 38 MMBbls in the Delaware and DJ Basins, respectively.
2019 additions of 52 MMBbls and 22 MMBbls in the DJ Basin and Delaware Basin, respectively, related to drilling plans for new wells.
|
| | |
| Noble Energy, Inc. | |
| Supplemental Oil and Gas Information | |
| | (Unaudited) | |
Extensions, Discoveries and Other Additions Oil extensions, discoveries and other additions included:
2016 extensions in US reserves included 38 MMBbls in the DJ Basin and 28 MMBbls in the Delaware Basin and Eagle Ford Shale, and was associated with increased performance from our horizontal drilling programs.
2017 extensions in US reserves included additions of 59 MMBbls in the Delaware Basin, 42 MMBbls in the DJ Basin and 3 MMBbls in the Eagle Ford Shale primarily due to the addition of planned new locations and activity.
2018 extensions relate to drilling plans for new wells and include 55 MMBbls, 38 MMBbls, 5 MMBbls and 3 MMBbls in the Delaware Basin, DJ Basin, Eagle Ford Shale and Equatorial Guinea, respectively.
Purchase of Minerals in Place The 2017 increase in oilpurchase was attributable to the reserves acquired in the Clayton Williams Energy Acquisition.
Sale of Minerals in PlaceSales of oil minerals in place included:
2017 includes the sale ofsales included Marcellus Shale upstream assets and other non-strategic US onshore assets.
2018 sales included 16 MMBbls related to our Gulf of Mexico assets and 8 MMBbls related to other non-strategic US onshore assets.
|
| | |
| Noble Energy, Inc. | |
| Supplemental Oil and Gas Information | |
| | (Unaudited) | |
Proved NGL Reserves (Unaudited) The following reserves schedule was developed by our qualified petroleum engineers and sets forth the changes in estimated quantities of proved NGL reserves: | | | | | NGLs (MMBbls) | | NGLs |
| | | United States | | Equatorial Guinea | | Total | |
| Proved Reserves as of: | | | | | | | |
| December 31, 2015 | | 176 |
| | 13 |
| | 189 |
| |
| Revisions of Previous Estimates | | 16 |
| | 1 |
| | 17 |
| |
| Extensions, Discoveries and Other Additions | | 31 |
| | — |
| | 31 |
| |
| Purchase of Minerals in Place | | 4 |
| | — |
| | 4 |
| |
| Production | | (20 | ) | | (2 | ) | | (22 | ) | |
| (MMBbls) | | | United States | | Equatorial Guinea | | Total |
| December 31, 2016 | | 207 |
| | 12 |
| | 219 |
| | 207 |
| | 12 |
| | 219 |
|
| Revisions of Previous Estimates | | 31 |
| | 1 |
| | 32 |
| |
| Price Revisions | | | 6 |
| | — |
| | 6 |
|
| Non-Price Revisions | | | 25 |
| | 1 |
| | 26 |
|
| Extensions, Discoveries and Other Additions | | 32 |
| | — |
| | 32 |
| | 32 |
| | — |
| | 32 |
|
| Purchase of Minerals in Place | | 7 |
| | — |
| | 7 |
| | 7 |
| | — |
| | 7 |
|
| Sale of Minerals in Place | | (38 | ) | | — |
| | (38 | ) | | (38 | ) | | — |
| | (38 | ) |
| Production | | (21 | ) | | (2 | ) | | (23 | ) | | (21 | ) | | (2 | ) | | (23 | ) |
| December 31, 2017 | | 218 |
| | 11 |
| | 229 |
| | 218 |
| | 11 |
| | 229 |
|
| Revisions of Previous Estimates | | 21 |
| | — |
| | 21 |
| |
| Price Revisions | | | 5 |
| | — |
| | 5 |
|
| Non-Price Revisions | | | 16 |
| | — |
| | 16 |
|
| Extensions, Discoveries and Other Additions | | 48 |
| | — |
| | 48 |
| | 48 |
| | — |
| | 48 |
|
| Sale of Minerals in Place | | (7 | ) | | — |
| | (7 | ) | | (7 | ) | | — |
| | (7 | ) |
| Production | | (23 | ) | | (2 | ) | | (25 | ) | | (23 | ) | | (2 | ) | | (25 | ) |
| December 31, 2018 | | 257 |
| | 9 |
| | 266 |
| | 257 |
| | 9 |
| | 266 |
|
| Price Revisions | | | (12 | ) | | (1 | ) | | (13 | ) |
| Non-Price Revisions | | | (4 | ) | | 3 |
| | (1 | ) |
| Extensions, Discoveries and Other Additions | | | 47 |
| | 5 |
| | 52 |
|
| Production | | | (25 | ) | | (1 | ) | | (26 | ) |
| December 31, 2019 | | | 263 |
| | 15 |
| | 278 |
|
| Proved Developed Reserves as of: | | |
| | |
| | | | |
| | |
| | |
| December 31, 2015 | | 101 |
| | 5 |
| | 106 |
| |
| December 31, 2016 | | 113 |
| | 12 |
| | 125 |
| | 113 |
| | 12 |
| | 125 |
|
| December 31, 2017 | | 119 |
| | 11 |
| | 130 |
| | 119 |
| | 11 |
| | 130 |
|
| December 31, 2018 | | 121 |
| | 9 |
| | 130 |
| | 121 |
| | 9 |
| | 130 |
|
| December 31, 2019 | | | 138 |
| | 10 |
| | 148 |
|
| Proved Undeveloped Reserves as of: | | | | | | | | | | | | |
| December 31, 2015 | | 75 |
| | 8 |
| | 83 |
| |
| December 31, 2016 | | 94 |
| | — |
| | 94 |
| | 94 |
| | — |
| | 94 |
|
| December 31, 2017 | | 99 |
| | — |
| | 99 |
| | 99 |
| | — |
| | 99 |
|
| December 31, 2018 | | 136 |
| | — |
| | 136 |
| | 136 |
| | — |
| | 136 |
|
| December 31, 2019 | | | 125 |
| | 5 |
| | 130 |
|
Revisions of Previous Estimates NGL revisions included:
Price Revisions
| |
◦ | 2016 included negative price revisions of 4 MMBbls. |
| |
◦ | 2017 included positive price revisions of 6 MMBbls. |
| |
◦ | 2018 included include positive price revisions of 5 MMBbls in the US. |
Non-Price Revisions
| |
◦ | 2016 US revisions were primarily associated with positive performance revisions of 11 MMBbls in the Marcellus Shale and 9 MMBbls in the DJ Basin. |
| |
◦ | 2017 US revisions associated with positive performance revisions totaled 25 MMBbls, including2017 US revisions included 11 MMBbls in the Delaware Basin, 8 MMBbls in the Eagle Ford Shale and 6 MMBbls in the DJ Basin, due to continued optimization of well development and improved producing well performance. |
| |
◦ | 2018 net positive non-price revisions of 16 MMBbls include positive revisions of 35 MMBbls in the DJ Basin primarily due to ASC 606 adoption, offset by negative revisions of 15 MMBbls in the Eagle Ford Shale due to changes in the previously adopted development plan and 4 MMBbls in the Delaware Basin for changes in expected recoveries and increased operating and capital costs. |
|
| | |
| Noble Energy, Inc. | |
| Supplemental Oil and Gas Information | |
| (Unaudited) | |
Extensions, Discoveries and Other AdditionsNGL extensions, discoveries and other additions included:
2016 extensions in US reserves primarily included an increase of 15 MMBbls in the DJ Basin and 14 MMBbls in the Delaware Basin and Eagle Ford shale due to improved well performance and/or decreases in development or operating costs.
2017 extensions in US reserves included 19 MMBbls in the DJ Basin, 9 MMBbls in the Delaware Basin and 4 MMBbls in the Eagle Ford Shale primarily due to the addition of planned new locations and activity.
2018 extensions relaterelated to the addition of planned new locations and activity, of which 25 MMBbls, 15 MMBbls and 8 MMBbls relaterelated to the DJ Basin, Delaware Basin and Eagle Ford Shale, respectively.
2019 extensions included additions of 40 MMBbls in the DJ Basin due to drilling plans for new wells.
Sale of Minerals in PlaceSales of NGL minerals in place included:
2017 sales included the Marcellus Shale upstream assets and other non-strategic US onshore assets.
2018 sales included 1 MMBbl from Gulf of Mexico assets and 6 MMBbls for certain non-core US onshore assets.
|
| | |
| Noble Energy, Inc. | |
| Supplemental Oil and Gas Information | |
| | (Unaudited) | |
Proved Gas Reserves (Unaudited) The following reserves schedule was developed by our qualified petroleum engineers and sets forth the changes in estimated quantities of proved natural gas reserves: | | | | | Natural Gas and Casinghead Gas (Bcf) | | Natural Gas |
| | | United States | | Israel | | Equatorial Guinea | | Total | |
| Proved Reserves as of: | | | | | | | | | |
| December 31, 2015 | | 2,711 |
| | 2,304 |
| | 534 |
| | 5,549 |
| |
| Revisions of Previous Estimates | | 181 |
| | (3 | ) | | 38 |
| | 216 |
| |
| Extensions, Discoveries and Other Additions | | 492 |
| | — |
| | — |
| | 492 |
| |
| Sale of Minerals in Place | | (224 | ) | | (214 | ) | | — |
| | (438 | ) | |
| Production | | (322 | ) | | (103 | ) | | (86 | ) | | (511 | ) | |
| (Bcf) | | | United States | | Israel | | Equatorial Guinea | | Total |
| December 31, 2016 | | 2,838 |
| | 1,984 |
| | 486 |
| | 5,308 |
| | 2,838 |
| | 1,984 |
| | 486 |
| | 5,308 |
|
| Revisions of Previous Estimates | | 124 |
| | 292 |
| | 13 |
| | 429 |
| |
| Price Revisions | | | 53 |
| | — |
| | 13 |
| | 66 |
|
| Non-Price Revisions | | | 71 |
| | 292 |
| | — |
| | 363 |
|
| Extensions, Discoveries and Other Additions | | 299 |
| | 3,271 |
| | — |
| | 3,570 |
| | 299 |
| | 3,271 |
| | — |
| | 3,570 |
|
| Purchase of Minerals in Place | | 46 |
| | — |
| | — |
| | 46 |
| | 46 |
| | — |
| | — |
| | 46 |
|
| Sale of Minerals in Place | | (1,264 | ) | | — |
| | (1 | ) | | (1,265 | ) | | (1,264 | ) | | — |
| | (1 | ) | | (1,265 | ) |
| Production | | (222 | ) | | (99 | ) | | (87 | ) | | (408 | ) | | (222 | ) | | (99 | ) | | (87 | ) | | (408 | ) |
| December 31, 2017 | | 1,821 |
| | 5,448 |
| | 411 |
| | 7,680 |
| | 1,821 |
| | 5,448 |
| | 411 |
| | 7,680 |
|
| Revisions of Previous Estimates | | 1 |
| | 2 |
| | 22 |
| | 25 |
| |
| Price Revisions | | | 44 |
| | — |
| | 5 |
| | 49 |
|
| Non-Price Revisions | | | (43 | ) | | 2 |
| | 17 |
| | (24 | ) |
| Extensions, Discoveries and Other Additions | | 373 |
| | 68 |
| | 2 |
| | 443 |
| | 373 |
| | 68 |
| | 2 |
| | 443 |
|
| Sale of Minerals in Place | | (79 | ) | | (502 | ) | | — |
| | (581 | ) | | (79 | ) | | (502 | ) | | — |
| | (581 | ) |
| Production | | (172 | ) | | (86 | ) | | (78 | ) | | (336 | ) | | (172 | ) | | (86 | ) | | (78 | ) | | (336 | ) |
| December 31, 2018 | | 1,944 |
| | 4,930 |
| | 357 |
| | 7,231 |
| | 1,944 |
| | 4,930 |
| | 357 |
| | 7,231 |
|
| Price Revisions | | | (81 | ) | | — |
| | 7 |
| | (74 | ) |
| Non-Price Revisions | | | (33 | ) | | 226 |
| | 77 |
| | 270 |
|
| Extensions, Discoveries and Other Additions | | | 377 |
| | 520 |
| | 167 |
| | 1,064 |
|
| Production | | | (188 | ) | | (81 | ) | | (71 | ) | | (340 | ) |
| December 31, 2019 | | | 2,019 |
| | 5,595 |
| | 537 |
| | 8,151 |
|
| Proved Developed Reserves as of: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| December 31, 2015 | | 1,813 |
| | 1,879 |
| | 247 |
| | 3,939 |
| |
| December 31, 2016 | | 1,817 |
| | 1,600 |
| | 486 |
| | 3,903 |
| | 1,817 |
| | 1,600 |
| | 486 |
| | 3,903 |
|
| December 31, 2017 | | 983 |
| | 1,793 |
| | 411 |
| | 3,187 |
| | 983 |
| | 1,793 |
| | 411 |
| | 3,187 |
|
| December 31, 2018 | | 929 |
| | 1,295 |
| | 355 |
| | 2,579 |
| | 929 |
| | 1,295 |
| | 355 |
| | 2,579 |
|
| December 31, 2019 | | | 1,055 |
| | 5,463 |
| | 355 |
| | 6,873 |
|
| Proved Undeveloped Reserves as of: | | | | | | | | | | | | | | | | |
| December 31, 2015 | | 898 |
| | 425 |
| | 287 |
| | 1,610 |
| |
| December 31, 2016 | | 1,021 |
| | 384 |
| | — |
| | 1,405 |
| | 1,021 |
| | 384 |
| | — |
| | 1,405 |
|
| December 31, 2017 | | 838 |
| | 3,655 |
| | — |
| | 4,493 |
| | 838 |
| | 3,655 |
| | — |
| | 4,493 |
|
| December 31, 2018 | | 1,015 |
| | 3,635 |
| | 2 |
| | 4,652 |
| | 1,015 |
| | 3,635 |
| | 2 |
| | 4,652 |
|
| December 31, 2019 | | | 964 |
| | 132 |
| | 182 |
| | 1,278 |
|
Revisions of Previous Estimates Gas revisions included:
Price Revisions
| |
◦ | 2016 included negative commodity price revisions of 81 Bcf in the US and 20 Bcf in Equatorial Guinea. |
| |
◦ | 2017 included positive commodity price revisions of 53 Bcf in the US and 13 Bcf in Equatorial Guinea. |
| |
◦ | 2018 included positive price revisions of 44 Bcf in the US and 5 Bcf in Equatorial Guinea. |
Non-Price Revisions
| |
◦ | 2016 US revisions were primarily associated with positive performance and/or decreases in development or operating costs and included 167 Bcf in the Marcellus Shale and 95 Bcf in the DJ Basin. Equatorial Guinea revisions were associated with positive performance revisions of 58 Bcf at the Alba field. |
| |
◦ | 2017 performance revisions of 66 Bcf primarily included 81 Bcf in the Eagle Ford Shale and 31 Bcf in the Delaware Basin, partially offset by negative performance revisions of 49 Bcf in the DJ Basin primarily associated vertical well locations. |
2017 US revisions included 81 Bcf in the Eagle Ford Shale and 31 Bcf in the Delaware Basin, partially offset by negative performance revisions of 49 Bcf in the DJ Basin primarily associated vertical well locations. The Israel revision was associated with the integration of the Tamar 8 well results in our geologic modeling across the reservoir.
2018 US revisions included positive revisions of 70 Bcf in the DJ Basin primarily due to ASC 606 adoption, offset by negative revisions of 71 Bcf in the Eagle Ford Shale due to changes in the previously adopted development plan and 42 Bcf primarily in the Delaware Basin due to changes in expected recoveries and increased operating and capital costs. Additional reserves of 17 Bcf in Equatorial Guinea and 2 Bcf in Israel relate to improved recoveries on existing wells.
2019 revisions in US onshore included a 41 Bcf negative revision in the Eagle Ford Shale due to performance, partially offset by positive revisions due to performance in the DJ Basin. In Israel, revisions to our Tamar field included positive revisions to developed reserves of 460 Bcf, partially offset by revisions to PUD reserves of 241 Bcf. The Tamar field PUDs were reclassified to developed reserves based on our determination the reserves are accessible with limited further development. Equatorial Guinea revisions relate to the sanction of the Alen Gas Monetization project, which extends the life of the Alba field as certain natural gas volumes are now economic to produce.
Extensions, Discoveries and Other Additions
2017 extensions in US reserves included additions of 224 Bcf in the DJ Basin, 53 Bcf in the Delaware Basin and 22 Bcf in
|
| | |
| Noble Energy, Inc. | |
| Supplemental Oil and Gas Information | |
| | (Unaudited) | |
| |
◦ | 2018 net negative revisions of 24 Bcf include negative performance revisions of 43 Bcf in the US, partially offset by positive revisions of 19 Bcf in Equatorial Guinea and Israel. US includes positive revisions of 70 Bcf in the DJ Basin primarily due to ASC 606 adoption, offset by negative revisions of 71 Bcf in the Eagle Ford Shale due to changes in the previously adopted development plan and 42 Bcf primarily in the Delaware Basin due to changes in expected recoveries and increased operating and capital costs. Additional reserves of 17 Bcf in Equatorial Guinea and 2 Bcf in Israel relate to improved recoveries on existing wells. |
Extensions, Discoveries and Other Additions Gas extensions, discoveries and other additions included:
2016 extensions in US reserves included positive performance revisions associated with our horizontal drilling programs including 230 Bcf in the Marcellus Shale, 185 Bcf in the DJ Basin, and 77 Bcf in the Delaware Basin and Eagle Ford Shale.
2017 extensions in US reserves included additions of 224 Bcf in the DJ Basin, 53 Bcf in the Delaware Basin and 22 Bcf in the Eagle Ford Shale primarily due to the addition of planned new locations and activity. The 2017 increase in Israel reserves represented sanction of the first phase of development of the Leviathan natural gas project.
2018 extensions in reserves relaterelated to drilling plans for new wells. Increases in the US includeincluded 254 Bcf, 77 Bcf and 42 Bcf in the DJ Basin, Delaware Basin and Eagle Ford Shale, respectively, and the increase in Israel of 68 Bcf relatesrelated to the Tamar field.
2019 extensions in US onshore included additions of 345 Bcf in the DJ Basin due to drilling plans for new wells. Israel additions relate to the Leviathan field and are due to closing of the EMG Pipeline transaction and signing of amendments to our natural gas sales agreements with Egyptian customers, which significantly increase our firm sales commitments in the region. Additions in Equatorial Guinea relate to sanction of the Alen Gas Monetization project in second quarter 2019.
Sale of Minerals in PlaceSales of gas minerals in place included:
2016 included the sale of non-strategic US onshore assets, an acreage exchange in the Marcellus Shale where we relinquished 185 Bcf, and we sold a 3.5% ownership interest in the Tamar field, offshore Israel.
2017 sales included the sale of our Marcellus Shale upstream assets and other non-strategic US onshore assets.
2018 sales included 20 Bcf for our Gulf of Mexico assets, 59 Bcf for other non-strategic US onshore assets and 502 Bcf for a 7.5% working interest in the Tamar field, offshore Israel.
|
| | |
| Noble Energy, Inc. | |
| Supplemental Oil and Gas Information | |
| | (Unaudited) | |
Results of Operations for Oil and Gas Producing Activities (Unaudited) Results of operations for crude oil, NGLs and natural gas producing activities within the E&P reporting segments are as follows: | | (millions) | | United States | | Israel | | Equatorial Guinea | | Other Int'l | | Total | United States | | Israel | | Equatorial Guinea | | Other Int'l | | Total |
| Year Ended December 31, 2019 | | |
| | |
| | |
| | |
| | |
|
| Revenues | | $ | 3,253 |
| | $ | 457 |
| | $ | 372 |
| | $ | — |
| | $ | 4,082 |
|
Production Costs (1) | | 1,284 |
| | 48 |
| | 90 |
| | 1 |
| | 1,423 |
|
Exploration Expense (2) | | 57 |
| | 103 |
| | 4 |
| | 38 |
| | 202 |
|
| Depreciation, Depletion and Amortization | | 1,907 |
| | 67 |
| | 83 |
| | 1 |
| | 2,058 |
|
Asset Impairments (3) | | 1,160 |
| | — |
| | — |
| | — |
| | 1,160 |
|
| Marketing Expense | | 27 |
| | 6 |
| | — |
| | — |
| | 33 |
|
| (Loss) Income before Income Taxes | | (1,182 | ) | | 233 |
| | 195 |
| | (40 | ) | | (794 | ) |
Income Tax (Benefit) Expense (4) | | (248 | ) | | 54 |
| | 49 |
| | — |
| | (145 | ) |
Results of Operations (5) | | $ | (934 | ) | | $ | 179 |
| | $ | 146 |
| | $ | (40 | ) | | $ | (649 | ) |
| Year Ended December 31, 2018 | | |
| | |
| | |
| | |
| | |
| | | | | | | | | |
| Revenues | | $ | 3,590 |
| | $ | 480 |
| | $ | 543 |
| | $ | — |
| | $ | 4,613 |
| $ | 3,590 |
| | $ | 480 |
| | $ | 543 |
| | $ | — |
| | $ | 4,613 |
|
Production Costs (1) | | 1,276 |
| | 37 |
| | 110 |
| | 2 |
| | 1,425 |
| 1,276 |
| | 37 |
| | 110 |
| | 2 |
| | 1,425 |
|
| Exploration Expense | | 48 |
| | 2 |
| | 1 |
| | 78 |
| | 129 |
| 48 |
| | 2 |
| | 1 |
| | 78 |
| | 129 |
|
| DD&A | | 1,642 |
| | 60 |
| | 115 |
| | 2 |
| | 1,819 |
| |
Loss (Gain) on Divestitures, Net (2) | | 36 |
| | (376 | ) | | — |
| | — |
| | (340 | ) | |
| Depreciation, Depletion and Amortization | | 1,642 |
| | 60 |
| | 115 |
| | 2 |
| | 1,819 |
|
Loss (Gain) on Divestitures, Net (6) | | 36 |
| | (376 | ) | | — |
| | — |
| | (340 | ) |
Asset Impairments (3) | | 169 |
| | — |
| | — |
| | — |
| | 169 |
| 169 |
| | — |
| | — |
| | — |
| | 169 |
|
| Marketing Expense | | 40 |
| | — |
| | — |
| | — |
| | 40 |
| 40 |
| | — |
| | — |
| | — |
| | 40 |
|
| Gain on Asset Retirement Obligation Revisions | | — |
| | (8 | ) | | — |
| | (17 | ) | | (25 | ) | — |
| | (8 | ) | | — |
| | (17 | ) | | (25 | ) |
| Income (Loss) before Income Taxes | | 379 |
| | 765 |
| | 317 |
| | (65 | ) | | 1,396 |
| 379 |
| | 765 |
| | 317 |
| | (65 | ) | | 1,396 |
|
Income Tax Expense (4) | | 80 |
| | 176 |
| | 79 |
| | — |
| | 335 |
| 80 |
| | 176 |
| | 79 |
| | — |
| | 335 |
|
Results of Operations (5) | | $ | 299 |
| | $ | 589 |
| | $ | 238 |
| | $ | (65 | ) | | $ | 1,061 |
| $ | 299 |
| | $ | 589 |
| | $ | 238 |
| | $ | (65 | ) | | $ | 1,061 |
|
| Year Ended December 31, 2017 | | | | | | | | | | | | | | | | | | | |
| Revenues | | $ | 3,156 |
| | $ | 534 |
| | $ | 370 |
| | $ | — |
| | $ | 4,060 |
| $ | 3,156 |
| | $ | 534 |
| | $ | 370 |
| | $ | — |
| | $ | 4,060 |
|
Production Costs (1) | | 1,199 |
| | 49 |
| | 103 |
| | 2 |
| | 1,353 |
| 1,199 |
| | 49 |
| | 103 |
| | 2 |
| | 1,353 |
|
| Exploration Expense | | 102 |
| | — |
| | 1 |
| | 85 |
| | 188 |
| 102 |
| | — |
| | 1 |
| | 85 |
| | 188 |
|
| DD&A | | 1,739 |
| | 76 |
| | 146 |
| | 4 |
| | 1,965 |
| |
Loss on Marcellus Shale Upstream Divestiture and Other (6) | | 2,286 |
| | — |
| | — |
| | — |
| | 2,286 |
| |
| Depreciation, Depletion and Amortization | | 1,739 |
| | 76 |
| | 146 |
| | 4 |
| | 1,965 |
|
Loss on Marcellus Shale Upstream Divestiture and Other (5) | | 2,286 |
| | — |
| | — |
| | — |
| | 2,286 |
|
Asset Impairments (3) | | 63 |
| | — |
| | — |
| | 7 |
| | 70 |
| 63 |
| | — |
| | — |
| | 7 |
| | 70 |
|
| Marketing Expense | | 47 |
| | — |
| | — |
| | — |
| | 47 |
| 47 |
| | — |
| | — |
| | — |
| | 47 |
|
| Gain on Asset Retirement Obligation Revisions | | — |
| | — |
| | — |
| | (42 | ) | | (42 | ) | — |
| | — |
| | — |
| | (42 | ) | | (42 | ) |
| (Loss) Income before Income Taxes | | (2,280 | ) | | 409 |
| | 120 |
| | (56 | ) | | (1,807 | ) | (2,280 | ) | | 409 |
| | 120 |
| | (56 | ) | | (1,807 | ) |
Income Tax (Benefit) Expense (4) | | (798 | ) | | 98 |
| | 30 |
| | — |
| | (670 | ) | (798 | ) | | 98 |
| | 30 |
| | — |
| | (670 | ) |
Results of Operations (5) | | $ | (1,482 | ) | | $ | 311 |
| | $ | 90 |
| | $ | (56 | ) | | $ | (1,137 | ) | $ | (1,482 | ) | | $ | 311 |
| | $ | 90 |
| | $ | (56 | ) | | $ | (1,137 | ) |
| Year Ended December 31, 2016 | | | | | | | | | | | |
| Revenues | | $ | 2,416 |
| | $ | 540 |
| | $ | 433 |
| | $ | — |
| | $ | 3,389 |
| |
Production Costs (1) | | 1,108 |
| | 49 |
| | 118 |
| | 1 |
| | 1,276 |
| |
Exploration Expense (7) | | 245 |
| | 26 |
| | 469 |
| | 185 |
| | 925 |
| |
| DD&A | | 2,103 |
| | 81 |
| | 205 |
| | 6 |
| | 2,395 |
| |
Asset Impairments (3) | | — |
| | 88 |
| | — |
| | 4 |
| | 92 |
| |
| (Loss) Income before Income Taxes | | (1,040 | ) | | 296 |
| | (359 | ) | | (196 | ) | | (1,299 | ) | |
Income Tax (Benefit) Expense (4) | | (364 | ) | | 74 |
| | (90 | ) | | — |
| | (380 | ) | |
Results of Operations (5) | | $ | (676 | ) | | $ | 222 |
| | $ | (269 | ) | | $ | (196 | ) | | $ | (919 | ) | |
| |
(1) | Production costs consist of lease operating expense, production and ad valorem taxes, royalty expense, transportation and gathering expense, and general and administrative expense supporting oil and gas operations. |
| |
(2) | Amount for Israel includes $100 million for the write-off of the Leviathan Deep prospect. |
| |
(3) | 2018 asset impairments relate to the sale of our Gulf of Mexico assets.See Note 10. Impairments. |
2017 asset impairments relate primarily to the Gulf of Mexico Troubadour well.
2016 asset impairments relate to certain Leviathan development concept costs.
| |
(4) | Income tax (benefit) expense is based upon respective corporate statutory tax rates. During 2018, 2017, and 2016,all periods presented, we incurred exploration expense in currently non-commercial other international locations; therefore, no tax benefit was included in income tax expense associated withfor other international as we could not conclude it was more likely than not that some portion or all of the deferred tax assets would be realized. |
| |
(5) | Results of operations exclude the mark-to-market gain or loss on commodity derivative instruments, corporate activities, exit costs and certain costs associated with mitigating the effects of our retained Marcellus Shale firm transportation agreements, and overhead and interest costs. |
| |
(6) | See Note 13. Derivative Instruments4. Acquisitions and Hedging ActivitiesDivestitures. |
|
| | |
| Noble Energy, Inc. | |
| Supplemental Oil and Gas Information | |
| | (Unaudited) | |
| |
(6)
| Amount reflects reclassification of $93 million accrued exit costs for retained Marcellus Shale firm transportation commitments from our US oil and gas exploration and production reportable segment to our Corporate segment. See Note 1. Summary of Significant Accounting Policies, Note 3. Segment Information and Note 10. Marcellus Shale Firm Transportation Commitments. |
| |
(7)
| Equatorial Guinea exploration expense includes amounts related to the write off of costs associated with certain discoveries. See Note 7. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs. |
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities (Unaudited) Costs incurred include both capitalized costs and costs charged to expense when incurred for oil and gas property acquisition, exploration, and development activities associated with the E&P reporting segments. Costs incurred also include new AROs established in the current year, as well as changes to AROs resulting from changes to cost estimates during the year. Exploration costs presented below include the costs of drilling and equipping successful and unsuccessful exploration wells during the year, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells. Costs associated with activities of our Midstream segment and other corporate activities are not included.excluded. | | | (millions) | | United States | | Israel | | Equatorial Guinea | | Other Int'l (1) | | Total | | United States | | Israel | | Equatorial Guinea | | Other Int'l | | Total |
| December 31, 2019 | | | | | | | | | | | |
| Property Acquisition Costs | | | | | | | | | | | |
Proved (1) | | | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 4 |
|
Unproved (1) | | | 37 |
| | — |
| | — |
| | — |
| | 37 |
|
Exploration Costs (2) | | | 67 |
| | 14 |
| | 16 |
| | 43 |
| | 140 |
|
Development Costs (3) | | | 1,483 |
| | 522 |
| | 60 |
| | — |
| | 2,065 |
|
| Total Consolidated Operations | | | $ | 1,591 |
| | $ | 536 |
| | $ | 76 |
| | $ | 43 |
| | $ | 2,246 |
|
| December 31, 2018 | | | | | | | | | | | | |
| | |
| | |
| | |
| | |
|
| Property Acquisition Costs | | | | | | | | | | | |
Proved (2) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| |
Unproved (2) | | 41 |
| | — |
| | — |
| | — |
| | 41 |
| |
Exploration Costs (3) | | 58 |
| | 12 |
| | 10 |
| | 73 |
| | 153 |
| |
Development Costs (4) | | 2,303 |
| | 663 |
| | 20 |
| | (16 | ) | | 2,970 |
| |
| Total Consolidated Operations | | $ | 2,402 |
| | $ | 675 |
| | $ | 30 |
| | $ | 57 |
| | $ | 3,164 |
| |
| December 31, 2017 | | |
| | |
| | |
| | |
| | |
| |
| Property Acquisition Costs | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Proved (2)(1) | | $ | 839 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 839 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Unproved (2)(1) | | 1,817 |
| | — |
| | — |
| | — |
| | 1,817 |
| | 41 |
| | — |
| | — |
| | — |
| | 41 |
|
Exploration Costs (3)(2) | | 59 |
| | 6 |
| | 4 |
| | 90 |
| | 159 |
| | 58 |
| | 12 |
| | 10 |
| | 73 |
| | 153 |
|
Development Costs (4)(3) | | 1,870 |
| | 483 |
| | 33 |
| | (39 | ) | | 2,347 |
| | 2,303 |
| | 663 |
| | 20 |
| | (16 | ) | | 2,970 |
|
| Total Consolidated Operations | | $ | 4,585 |
| | $ | 489 |
| | $ | 37 |
| | $ | 51 |
| | $ | 5,162 |
| | $ | 2,402 |
| | $ | 675 |
| | $ | 30 |
| | $ | 57 |
| | $ | 3,164 |
|
| December 31, 2016 | | |
| | |
| | |
| | |
| | |
| |
| December 31, 2017 | | | |
| | |
| | |
| | |
| | |
|
| Property Acquisition Costs | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Proved (2) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| |
Unproved (2) | | 234 |
| | — |
| | — |
| | — |
| | 234 |
| |
Exploration Costs (3) | | 264 |
| | 26 |
| | 25 |
| | 44 |
| | 359 |
| |
Development Costs (4) | | 905 |
| | 109 |
| | 31 |
| | — |
| | 1,045 |
| |
Proved (1) | | | $ | 839 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 839 |
|
Unproved (1) | | | 1,817 |
| | — |
| | — |
| | — |
| | 1,817 |
|
Exploration Costs (2) | | | 59 |
| | 6 |
| | 4 |
| | 90 |
| | 159 |
|
Development Costs (3) | | | 1,870 |
| | 483 |
| | 33 |
| | (39 | ) | | 2,347 |
|
| Total Consolidated Operations | | $ | 1,403 |
| | $ | 135 |
| | $ | 56 |
| | $ | 44 |
| | $ | 1,638 |
| | $ | 4,585 |
| | $ | 489 |
| | $ | 37 |
| | $ | 51 |
| | $ | 5,162 |
|
| |
(1) | Other International includes Newfoundland, Suriname (until November 2018), Falkland Islands (until December 2018), other new ventures and previous North Sea operations, which are in the process of being decommissioned. |
| |
2019(2) | and2018 unproved property acquisition costs include US onshore undeveloped leasehold activity during the year. |
2017 proved and unproved property acquisition costs primarily include amounts allocated from the Clayton Williams Energy Acquisition and the Delaware Basin Acquisition. SeeNote 5. Acquisitions and Divestitures. 2016 unproved property acquisition costs relate to the termination of the Marcellus Shale joint development agreement. See Note 5.4. Acquisitions and Divestitures. | |
(3)(2)
| 2019 and 2018 exploration costs primarily relate primarily to lease rentals, seismic and staffing expense. 2019 costs exclude $100 million of dry hole expense drillingrelated to the Leviathan Deep prospect as the associated unproved capital costs and lease rentals.were incurred in prior years. |
2017 exploration costs primarily include capitalized interest on Gulf of Mexico projects, and $7 million dry hole cost related to the Araku-1 exploration well, offshore Suriname. The remainder relates toSuriname, and seismic expense and drilling costs.
2016 exploration costs include $44 million drilling and completion costs in the Gulf of Mexico.
| |
(4)(3)
| Worldwide development2019 costs include amounts spent to develop our PUDs totaled $1.5 billion. Of this amount, $1.1 billion, $399 million and $48 million related to the conversion of approximately $1.0 billionyear end 2018 PUDs to proved developed reserves in 2018, $1.2 billionUS onshore, the Leviathan field and the Aseng crude oil well, respectively. In addition, we spent $131 million to convert unproved reserves to proved developed reserves in 2017,US onshore and $656$24 million progressing PUDs that have not yet been converted to proved developed reserves. Development costs also included a decrease of $9 million in 2016.ARO, consisting of downward revisions of $57 million in US onshore partially offset by additions of $40 million in Israel related to Leviathan. |
2018 costs to develop our PUDs totaled $1.7 billion. Of this amount, $1.0 billion and $646 million were spent in US onshore and Leviathan field, respectively. In addition, we spent $355 million to convert unproved reserves to proved developed reserves in US onshore. Development costs also included $315 million due to upward revisions of ARO costs, $302 million of which was in US onshore.
2017 costs to develop our PUDs totaled $1.7 billion. Of this amount, $1.2 billion and $479 million were spent in US onshore and Leviathan field offshore Israel, respectively. Development costs also included downward revisions in ARO of $13 million. Other International costs include decreases in ARO of $40 million primarily associated with the North Sea abandonment project.
|
| | |
| Noble Energy, Inc. | |
| Supplemental Oil and Gas Information | |
| | (Unaudited) | |
US development costs include an increase of $302 million in ARO due primarily to upward revisions in 2018, a decrease of $17 million in 2017 and an increase of $20 million in 2016.
Israel development costs for 2018 include $646 million related to initial development of the Leviathan field. Israel development costs for 2017 include $416 million related to initial development of the Leviathan field and $63 million related to the Tamar 8 development well.
Israel development costs for 2016 relate primarily to development of the Tamar discovery. Israel development costs include increases in ARO of $13 million in 2018 and $4 million in 2017.
Equatorial Guinea development costs are de minimis in 2018, relate to the Alba field unitization project in 2017 and drilling and well completion and installation and construction of a compression platform in the Alba field in 2016. 2017 development costs include an increase in ARO of $14 million.
Other International development costs include decreases in ARO of $40 million in 2017 primarily associated with the North Sea abandonment project.
Capitalized Costs Relating to Oil and Gas Producing Activities (Unaudited) Aggregate capitalized costs relating to crude oil and natural gas producing activities within the E&P reporting segments are as follows: | | | | | December 31, | | December 31, |
| (millions) | | 2018 | | 2017 | | 2019 | | 2018 |
Unproved Oil and Gas Properties (1) | | $ | 2,321 |
| | $ | 2,978 |
| |
Unproved Undeveloped Leasehold and Other (1) | | | $ | 2,152 |
| | $ | 2,321 |
|
Unproved Capitalized Exploratory Well Costs (1) | | | 280 |
| | 348 |
|
Proved Oil and Gas Properties (2) | | 24,955 |
| | 26,111 |
| | 26,658 |
| | 24,607 |
|
| Total Oil and Gas Properties | | 27,276 |
| | 29,089 |
| | 29,090 |
| | 27,276 |
|
| Accumulated DD&A | | (10,867 | ) | | (12,538 | ) | |
| Accumulated Depreciation, Depletion and Amortization | | | (13,353 | ) | | (10,867 | ) |
| Net Capitalized Costs | | $ | 16,409 |
| | $ | 16,551 |
| | $ | 15,737 |
| | $ | 16,409 |
|
| |
(1) | Unproved oilSee Note 6. Capitalized Exploratory Well Costs and gas property costs at December 31, 2018 include previous acquisition costs of $2.2 billion related to Delaware Basin properties and $100 million related to Eagle Ford Shale properties.Undeveloped Leasehold Costs. |
Unproved oil and gas property costs at December 31, 2017 include previous acquisition costs of $2.7 billion related to Delaware Basin properties and $149 million related to Eagle Ford Shale properties.
| |
(2) | Proved oil and gas properties atAt December 31, 2018 include2019, includes asset retirement costs of $954 million and assets held for sale of $14 million. |
At December 31, 2018, includes asset retirement costs of $966 million and assets held for sale of $133 million.
Proved oil and gas properties at December 31, 2017 include asset retirement costs of $941 million and assets held for sale of $448 million.
|
| | |
| Noble Energy, Inc. | |
| Supplemental Oil and Gas Information | |
| (Unaudited) | |
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited) The following information is based on our best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows in accordance with US GAAP. The standards require the use of a 10% discount rate. This information is not the fair value, nor does it represent the expected present value of future cash flows of our proved oil and gas reserves. | | | (millions) | | United States | | Israel (1) | | Equatorial Guinea | | Other Int'l (2) | | Total | | United States | | Israel (1) | | Equatorial Guinea | | Other Int'l (2) | | Total |
| December 31, 2019 | | | | | | | | | | | |
Future Cash Inflows (3) | | | $ | 27,965 |
| | $ | 30,865 |
| | $ | 2,760 |
| | $ | — |
| | $ | 61,590 |
|
Future Production Costs (4) | | | (12,453 | ) | | (2,945 | ) | | (1,172 | ) | | — |
| | (16,570 | ) |
Future Development Costs (5) | | | (4,966 | ) | | (418 | ) | | (269 | ) | | (23 | ) | | (5,676 | ) |
Future Income Tax Expense (6) | | | (466 | ) | | (13,877 | ) | | (338 | ) | | — |
| | (14,681 | ) |
| Future Net Cash Flows | | | 10,080 |
| | 13,625 |
| | 981 |
| | (23 | ) | | 24,663 |
|
| 10% Annual Discount for Estimated Timing of Cash Flows | | | (4,110 | ) | | (8,360 | ) | | (211 | ) | | — |
| | (12,681 | ) |
| Standardized Measure of Discounted Future Net Cash Flows | | | $ | 5,970 |
| | $ | 5,265 |
| | $ | 770 |
| | $ | (23 | ) | | $ | 11,982 |
|
| December 31, 2018 | | | | | | | | | | | | | | | | | | | | |
Future Cash Inflows (3) | | $ | 38,542 |
| | $ | 27,559 |
| | $ | 2,528 |
| | $ | — |
| | $ | 68,629 |
| | $ | 38,542 |
| | $ | 27,559 |
| | $ | 2,528 |
| | $ | — |
| | $ | 68,629 |
|
Future Production Costs (4) | | (14,793 | ) | | (2,478 | ) | | (1,180 | ) | | — |
| | (18,451 | ) | | (14,793 | ) | | (2,478 | ) | | (1,180 | ) | | — |
| | (18,451 | ) |
Future Development Costs (5) | | (5,793 | ) | | (1,038 | ) | | (170 | ) | | (32 | ) | | (7,033 | ) | | (5,793 | ) | | (1,038 | ) | | (170 | ) | | (32 | ) | | (7,033 | ) |
Future Income Tax Expense (6) | | (2,061 | ) | | (12,185 | ) | | (277 | ) | | — |
| | (14,523 | ) | |
| Future Income Tax Expense | | | (2,061 | ) | | (12,185 | ) | | (277 | ) | | — |
| | (14,523 | ) |
| Future Net Cash Flows | | 15,895 |
| | 11,858 |
| | 901 |
| | (32 | ) | | 28,622 |
| | 15,895 |
| | 11,858 |
| | 901 |
| | (32 | ) | | 28,622 |
|
| 10% Annual Discount for Estimated Timing of Cash Flows | | (6,493 | ) | | (8,037 | ) | | (158 | ) | | 4 |
| | (14,684 | ) | | (6,493 | ) | | (8,037 | ) | | (158 | ) | | 4 |
| | (14,684 | ) |
| Standardized Measure of Discounted Future Net Cash Flows | | $ | 9,402 |
| | $ | 3,821 |
| | $ | 743 |
| | $ | (28 | ) | | $ | 13,938 |
| | $ | 9,402 |
| | $ | 3,821 |
| | $ | 743 |
| | $ | (28 | ) | | $ | 13,938 |
|
| December 31, 2017 | | | | | | | | | | | | | | | | | | | | |
Future Cash Inflows (3) | | $ | 30,061 |
| | $ | 29,998 |
| | $ | 2,028 |
| | $ | — |
| | $ | 62,087 |
| | $ | 30,061 |
| | $ | 29,998 |
| | $ | 2,028 |
| | $ | — |
| | $ | 62,087 |
|
Future Production Costs (4) | | (11,020 | ) | | (2,517 | ) | | (932 | ) | | — |
| | (14,469 | ) | | (11,020 | ) | | (2,517 | ) | | (932 | ) | | — |
| | (14,469 | ) |
Future Development Costs (5) | | (5,941 | ) | | (1,706 | ) | | (109 | ) | | (51 | ) | | (7,807 | ) | | (5,941 | ) | | (1,706 | ) | | (109 | ) | | (51 | ) | | (7,807 | ) |
| Future Income Tax Expense | | (948 | ) | | (13,088 | ) | | (216 | ) | | — |
| | (14,252 | ) | | (948 | ) | | (13,088 | ) | | (216 | ) | | — |
| | (14,252 | ) |
| Future Net Cash Flows | | 12,152 |
| | 12,687 |
| | 771 |
| | (51 | ) | | 25,559 |
| | 12,152 |
| | 12,687 |
| | 771 |
| | (51 | ) | | 25,559 |
|
| 10% Annual Discount for Estimated Timing of Cash Flows | | (5,202 | ) | | (8,993 | ) | | (113 | ) | | 7 |
| | (14,301 | ) | | (5,202 | ) | | (8,993 | ) | | (113 | ) | | 7 |
| | (14,301 | ) |
| Standardized Measure of Discounted Future Net Cash Flows | | $ | 6,950 |
| | $ | 3,694 |
| | $ | 658 |
| | $ | (44 | ) | | $ | 11,258 |
| | $ | 6,950 |
| | $ | 3,694 |
| | $ | 658 |
| | $ | (44 | ) | | $ | 11,258 |
|
| December 31, 2016 | | | | | | | | | | | |
Future Cash Inflows (3) | | $ | 19,924 |
| | $ | 10,159 |
| | $ | 1,851 |
| | $ | — |
| | $ | 31,934 |
| |
Future Production Costs (4) | | (8,756 | ) | | (764 | ) | | (1,001 | ) | | — |
| | (10,521 | ) | |
Future Development Costs (5) | | (4,813 | ) | | (725 | ) | | (83 | ) | | (100 | ) | | (5,721 | ) | |
| Future Income Tax Expense | | (941 | ) | | (4,228 | ) | | (141 | ) | | — |
| | (5,310 | ) | |
| Future Net Cash Flows | | 5,414 |
| | 4,442 |
| | 626 |
| | (100 | ) | | 10,382 |
| |
| 10% Annual Discount for Estimated Timing of Cash Flows | | (2,308 | ) | | (2,329 | ) | | (84 | ) | | 25 |
| | (4,696 | ) | |
| Standardized Measure of Discounted Future Net Cash Flows | | $ | 3,106 |
| | $ | 2,113 |
| | $ | 542 |
| | $ | (75 | ) | | $ | 5,686 |
| |
| |
(1) | In accordance with the Framework,During 2018, we were required to reducereduced our ownership in the Tamar and Dalit fields from 36% to 25% by year-end 2021.During 2016, we reduced our ownership to 32.5% through the sale of a 3.5% interest. During 2018, we reduced our ownershipfield, offshore Israel, to 25% through the sale of a 7.5% interest. Therefore, amountsAmounts at December 31, 2019 and December 31, 2018 reflect a 25% interest while amounts at December 31, 2017 and 2016 reflect a 32.5% working interest. See Note 5.4. Acquisitions and Divestitures. TheIn 2017, increase in the standardized measure of discounted future net cash inflows relates primarily to the sanction ofwe sanctioned the first phase of development of the Leviathan field. |
| |
(2) | Other International represents changes in North Sea abandonment costs. |
|
| | |
| Noble Energy, Inc. | |
| Supplemental Oil and Gas Information | |
| (Unaudited) | |
| |
(3) | The standardized measure of discounted future net cash flows does not include cash flows relating to anticipatedExcludes future methanol sales. |
| |
(4) | Production costs include lease operating expense, production and ad valorem taxes, transportation expense and general and administrative expense supporting crude oil and natural gas operations. |
| |
(5) | Future development costs include future abandonment costs for each location. See Note 8.7. Asset Retirement Obligations. |
| |
(6) | Future income tax expense includes the effect of statutory tax rates and the impact of tax deductions, tax credits and allowances relating to our proved reserves. As of December 31, 2017, US future income tax expense includes the expected impact of the recent Tax Reform Legislation. As of December 31, 2018, 2017 and 2016, futureFuture income tax expense for Israel also includes the effect of estimated future profit levy taxes and changes to corporate income tax rates. |
|
| | |
| 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-endyear end quantities of proved reserves, except in those instances where fixed and determinable price changes are provided by contractual arrangements at year-end.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 | | Israel | | Equatorial Guinea | | Total | | United States | | Israel | | Equatorial Guinea (1) | | Total |
| December 31, 2019 | | | | | | | | | |
| Average Crude Oil and Condensate Price per Bbl | | | $ | 56.00 |
| | $ | 57.42 |
| | $ | 59.33 |
| | $ | 56.25 |
|
| Average NGL Price per Bbl | | | 13.24 |
| | — |
| | 30.53 |
| | 14.18 |
|
| Average Natural Gas Price per Mcf | | | 1.74 |
| | 5.42 |
| | 1.24 |
| | 4.23 |
|
| December 31, 2018 | | | | | | | | | | | | | | | | |
| Average Crude Oil and Condensate Price per Bbl | | $ | 66.66 |
| | $ | 63.94 |
| | $ | 70.92 |
| | $ | 66.88 |
| | 66.66 |
| | 63.94 |
| | 70.92 |
| | 66.88 |
|
| Average NGL Price per Bbl | | | 24.48 |
| | — |
| | 45.15 |
| | 25.19 |
|
| Average Natural Gas Price per Mcf | | 2.17 |
| | 5.49 |
| | 0.27 |
| | 4.34 |
| | 2.17 |
| | 5.49 |
| | 0.27 |
| | 4.34 |
|
| Average NGL Price per Bbl | | 24.48 |
| | — |
| | 45.15 |
| | 25.19 |
| |
| December 31, 2017 | | | | | | | | | | | | | | | | |
| Average Crude Oil and Condensate Price per Bbl | | $ | 47.81 |
| | $ | 46.82 |
| | $ | 53.12 |
| | $ | 48.13 |
| | 47.81 |
| | 46.82 |
| | 53.12 |
| | 48.13 |
|
| Average NGL Price per Bbl | | | 22.32 |
| | — |
| | 37.23 |
| | 23.02 |
|
| Average Natural Gas Price per Mcf | | 2.83 |
| | 5.43 |
| | 0.27 |
| | 4.54 |
| | 2.83 |
| | 5.43 |
| | 0.27 |
| | 4.54 |
|
| Average NGL Price per Bbl | | 22.32 |
| | — |
| | 37.23 |
| | 23.02 |
| |
| December 31, 2016 | | | | | | | | | |
| Average Crude Oil and Condensate Price per Bbl | | $ | 37.36 |
| | $ | 36.05 |
| | $ | 42.45 |
| | $ | 37.87 |
| |
| Average Natural Gas Price per Mcf | | 2.07 |
| | 5.07 |
| | 0.27 |
| | 3.02 |
| |
| Average NGL Price per Bbl | | 14.30 |
| | — |
| | 26.12 |
| | 14.94 |
| |
| |
(1) | Natural gas from the Alba field is sold for $0.25 per MMBtu and is adjusted for energy content. In 2019, we recorded natural gas PUDs associated with the Alen Gas Monetization project with future cash inflows from LNG sales estimated based upon pricing linked principally to the ICE Brent index. |
The discounted future net cash flows are computed using a 12-month average commodity price applied to our year-end quantities of proved reserves, unless contractual arrangements designate the price to be used. We performed a sensitivity of our discounted future net cash flows to reflect a price reduction to our 12-month average commodity price. We estimate that a 10% per Bbl reduction in the average price of crude oil and NGLs from the 12-month average price for 20182019 would reduce the discounted future net cash flows before income taxes by approximately $1.6$1.2 billion and $0.3 billion,$192 million, respectively. We estimate that a 10% per Mcf reduction in the average price of natural gas from the 12-month average price for 20182019 would reduce the discounted future net cash flows before income taxes by approximately $0.9$1.0 billion.
Future production and development costs, which include dismantlement and restoration expense, are computed by estimating the expenditures to be incurred in developing and producing the proved crude oil, NGL and natural gas reserves at the end of the year, based on year-endyear end costs, and assuming continuation of existing economic conditions.
Future development costs include amounts that we expect to spend to develop PUDs of approximately $2.1 billion in 2019, $1.5$1.2 billion in 2020, $920 million in 2021 and $1.1$1.0 billion in 2021.2022.
Future income tax expense is computed by applying the appropriate year-endyear end statutory tax rates to the estimated future pre-tax net cash flows relating to proved crude oil, NGL 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.
|
| | |
| 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, NGL and natural gas reserves are as follows: | | | | | Year Ended December 31, | | Year Ended December 31, |
| (millions) | | 2018 | | 2017 | | 2016 | | 2019 | | 2018 | | 2017 |
| Standardized Measure of Discounted Future Net Cash Flows, Beginning of Year | | $ | 11,258 |
| | $ | 5,686 |
| | $ | 6,628 |
| | $ | 13,938 |
| | $ | 11,258 |
| | $ | 5,686 |
|
| Changes in Standardized Measure of Discounted Future Net Cash Flows | | | | | | | | | | | | |
| Sales of Oil and Gas Produced, Net of Production Costs | | (3,190 | ) | | (2,674 | ) | | (2,230 | ) | | (2,660 | ) | | (3,190 | ) | | (2,674 | ) |
Net Changes in Prices and Production Costs (1) | | 2,327 |
| | 2,436 |
| | (593 | ) | | (4,748 | ) | | 2,327 |
| | 2,436 |
|
| Extensions, Discoveries and Improved Recovery, Less Related Costs | | 2,036 |
| | 3,711 |
| | 463 |
| | 1,858 |
| | 2,036 |
| | 3,711 |
|
Changes in Estimated Future Development Costs | | (738 | ) | | (537 | ) | | (373 | ) | | 729 |
| | (738 | ) | | (537 | ) |
| Development Costs Incurred During the Period | | 2,986 |
| | 1,975 |
| | 1,090 |
| | 2,070 |
| | 2,986 |
| | 1,975 |
|
| Revisions of Previous Quantity Estimates | | (9 | ) | | 1,462 |
| | 364 |
| | (483 | ) | | (9 | ) | | 1,462 |
|
Purchases of Minerals in Place (2)(3) | | — |
| | 423 |
| | 161 |
| | — |
| | — |
| | 423 |
|
Sales of Minerals in Place (3)(4) | | (1,873 | ) | | (643 | ) | | (951 | ) | | (28 | ) | | (1,873 | ) | | (643 | ) |
| Accretion of Discount | | 1,538 |
| | 778 |
| | 919 |
| | 1,807 |
| | 1,538 |
| | 778 |
|
Net Change in Income Taxes (4)(5) | | (11 | ) | | (1,669 | ) | | 414 |
| | (35 | ) | | (11 | ) | | (1,669 | ) |
| Change in Timing of Estimated Future Production and Other | | (386 | ) | | 310 |
| | (206 | ) | | (466 | ) | | (386 | ) | | 310 |
|
| Aggregate Change in Standardized Measure of Discounted Future Net Cash Flows | | $ | 2,680 |
| | $ | 5,572 |
| | $ | (942 | ) | | $ | (1,956 | ) | | $ | 2,680 |
| | $ | 5,572 |
|
| Standardized Measure of Discounted Future Net Cash Flows, End of Year | | $ | 13,938 |
| | $ | 11,258 |
| | $ | 5,686 |
| | $ | 11,982 |
| | $ | 13,938 |
| | $ | 11,258 |
|
| |
(1) | The decrease in 2019 and increases in 2018 and 2017 were driven primarily by higher 12-month average commodity prices. |
| |
(2) | The decrease in 2019 relates to primarily to capital efficiencies in our US onshore program and changes in development plans in the Delaware Basin. |
| |
(3) | Purchase of minerals in 2017 relates to reserves acquired in the Clayton Williams Energy Acquisition. |
| |
(3)(4)
| See Note 5.4. Acquisitions and Divestitures. |
| |
(4)(5)
| The2019 increase in 2018 future income tax expense relates primarily to the increase in US tax expense due to higher future taxable incomecash flows from the Leviathan and a reduction of NOL carryforwards utilizedTamar fields and from cash flows attributable to offset future taxable income from $3.2 billion as of December 31, 2017 to $1.7 billion as of December 31, 2018. The increase isAlen Gas Monetization, partially offset by a decrease in US income tax expense due to lower future taxes in Israel driven by the sale of 7.5% working interest in Tamar.taxable income. |
2018 increase in future income tax expense relates primarily to higher US tax expense due to higher future taxable income and a reduction of NOL carryforwards utilized to offset future taxable income from $3.2 billion as of December 31, 2017 to $1.7 billion as of December 31, 2018. The increase is partially offset by a decrease in future taxes in Israel driven by the sale of 7.5% working interest in Tamar.
2017 increase in future income tax expense relates primarily to the increase in profit and levy taxes in Israel, partially offset by the decrease in the future corporate income tax rate in Israel. The increase in profits tax is driven by a significant increase in future cash flows related to the Leviathan project sanctioning in 2017. The increase in US tax expense due to the increase in future taxable income was offset by the decrease in tax expense associated with utilization of future net operating losses and decrease in applicable tax rate from 35% to 21% due to the changes in the US Tax Law effective January 1, 2018.
|
| | |
| Noble Energy, Inc. | |
| Supplemental Quarterly Financial Information | |
| | (Unaudited) | |
Supplemental quarterly financial information is as follows: | | | | | Quarter Ended | | | | | | | | | | | |
| | | March 31, | | June 30, | | Sep 30, | | Dec 31, | | Total | Quarter Ended | | |
| (millions except per share amounts) | | | | | | | | | | | March 31, | | June 30, | | Sep 30, | | Dec 31, | | Total |
2018 (1) (3) | | | | | | | | | | | |
2019 (1) (3) | | | | | | | | | | |
| Revenues | | $ | 1,052 |
| | $ | 1,093 |
| | $ | 1,119 |
| | $ | 1,174 |
| | $ | 4,438 |
|
| (Loss) Income Before Income Taxes | | (373 | ) | | 28 |
| | 51 |
| | (1,482 | ) | | (1,776 | ) |
| Net (Loss) Income Including Noncontrolling Interests | | (289 | ) | | 8 |
| | 36 |
| | (1,188 | ) | | (1,433 | ) |
| Less: Net Income Attributable to Noncontrolling Interests | | 24 |
| | 18 |
| | 19 |
| | 18 |
| | 79 |
|
| Net (Loss) Income Attributable to Noble Energy | | (313 | ) | | (10 | ) | | 17 |
| | (1,206 | ) | | (1,512 | ) |
| Net (Loss) Income Per Share, Basic | | (0.65 | ) | | (0.02 | ) | | 0.04 |
| | (2.52 | ) | | (3.16 | ) |
| Net (Loss) Income Per Share, Diluted | | (0.65 | ) | | (0.02 | ) | | 0.04 |
| | (2.52 | ) | | (3.16 | ) |
2018 (2) (3) | | | | | | | | | | |
| Revenues | | $ | 1,286 |
| | $ | 1,230 |
| | $ | 1,273 |
| | $ | 1,197 |
| | $ | 4,986 |
| $ | 1,286 |
| | $ | 1,230 |
| | $ | 1,273 |
| | $ | 1,197 |
| | $ | 4,986 |
|
| Income (Loss) Before Income Taxes | | 543 |
| | 10 |
| | 307 |
| | (720 | ) | | 140 |
| 543 |
| | 10 |
| | 307 |
| | (720 | ) | | 140 |
|
| Net Income (Loss) Including Noncontrolling Interests | | 574 |
| | (6 | ) | | 248 |
| | (802 | ) | | 14 |
| 574 |
| | (6 | ) | | 248 |
| | (802 | ) | | 14 |
|
| Less: Net Income Attributable to Noncontrolling Interests | | 20 |
| | 17 |
| | 21 |
| | 22 |
| | 80 |
| 20 |
| | 17 |
| | 21 |
| | 22 |
| | 80 |
|
| Net Income (Loss) Attributable to Noble Energy | | 554 |
| | (23 | ) | | 227 |
| | (824 | ) | | (66 | ) | 554 |
| | (23 | ) | | 227 |
| | (824 | ) | | (66 | ) |
| | | | | | | | | | | | |
| Net Income (Loss) Per Share, Basic | | 1.14 |
| | (0.05 | ) | | 0.47 |
| | (1.72 | ) | | (0.14 | ) | 1.14 |
| | (0.05 | ) | | 0.47 |
| | (1.72 | ) | | (0.14 | ) |
| Net Income (Loss) Per Share, Diluted | | 1.14 |
| | (0.05 | ) | | 0.47 |
| | (1.71 | ) | | (0.14 | ) | 1.14 |
| | (0.05 | ) | | 0.47 |
| | (1.72 | ) | | (0.14 | ) |
2017 (2) (3) | | | | | | | | | | | |
| Revenues | | $ | 1,036 |
| | $ | 1,059 |
| | $ | 960 |
| | $ | 1,201 |
| | $ | 4,256 |
| |
| Income (Loss) Before Income Taxes | | 59 |
| | (2,334 | ) | | (208 | ) | | 292 |
| | (2,191 | ) | |
| Net Income (Loss) | | 47 |
| | (1,498 | ) | | (115 | ) | | 516 |
| | (1,050 | ) | |
| Less: Net Income Attributable to Noncontrolling Interests | | 11 |
| | 14 |
| | 21 |
| | 22 |
| | 68 |
| |
| Net Income (Loss) Attributable to Noble Energy | | 36 |
| | (1,512 | ) | | (136 | ) | | 494 |
| | (1,118 | ) | |
| | | | | | | | | | | | |
| Net Income (Loss) Per Share, Basic | | 0.08 |
| | (3.20 | ) | | (0.28 | ) | | 1.01 |
| | (2.38 | ) | |
| Net Income (Loss) Per Share, Diluted | | 0.08 |
| | (3.20 | ) | | (0.28 | ) | | 1.01 |
| | (2.38 | ) | |
(1)First quarter 2019 included a $92 million firm transportation exit cost. See Note 11. Exit Cost – Transportation Commitments. Second and third quarters 2019 did not have any unusual or infrequently occurring items.
Fourth quarter 2019 included the following:
| |
| • | Proved property impairment charge of $1.2 billion in the Eagle Ford Shale. See Note 10. Impairments; and |
| |
| • | $100 million dry hole cost. See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs. |
(2) First quarter 2018 included the following:
| |
| • | $376572 million pre-tax gain on sale of 7.5% working interest in Tamar field.divestitures. See Note 5. Acquisitions and Divestitures; |
| |
• | $196 million pre-tax gain on sale of our 50% interest in CONE Gathering. See Note 5.4. Acquisitions and Divestitures; |
| |
| • | $168 million impairment expense related to Gulf of Mexico asset divestiture. See Note 5.4. Acquisitions and Divestitures; and |
| |
| • | $145 million discrete tax benefit, net, related to changes in federal income tax regulations. See Note 12.13. Income Taxes; and |
| |
• | $79 million loss on commodity derivative instruments, including non-cash portion of loss on commodity derivative instruments of $51 million. See Note 13. Derivative Instruments and Hedging Activities. |
Second quarter 2018 included the following:
| |
• | $249 million loss on commodity derivative instruments, including non-cash portion of loss on commodity derivative instrument of $184 million. See Note 13. Derivative Instruments and Hedging Activities; and |
| |
• | $109 million gain on sale of 7.5 million CNX Midstream Partners units. See Note 5. Acquisitions and Divestitures. |
Third quarter 2018 included the following:
| |
• | $198 million gain on sale of 14.2 million CNX Midstream Partners units. See Note 5. Acquisitions and Divestitures; and |
| |
• | $155 million loss on commodity derivative instruments, including non-cash portion of loss on commodity derivative instruments of $88 million. See Note 13. Derivative Instruments and Hedging Activities. |
Fourth quarter 2018 included the following:
| |
• | $1.3 billion goodwill impairment charge. See Note 6. Goodwill Impairment; |
| |
• | $546 million gain on commodity derivative instruments, including non-cash portion of gain on commodity derivative instruments of $547 million. See Note 13. Derivative Instruments and Hedging Activities; and |
| |
• | $38 million impairment expense primarily related to midstream assets. See Note 14. Fair Value Measurements and Disclosures. |
(2) First quarter 2017 included the following:
No unusual or infrequent activity.
Second quarter
20172018 included
the following:a $109 million gain on divestiture. See Note 4. Acquisitions and Divestitures. | |
• | $2.3 billion loss on Marcellus Shale upstream divestiture. See Note 5. Acquisitions and Divestitures. |
Third quarter
20172018 included
the following:a $198 million gain on divestiture See Note 4. Acquisitions and Divestitures. | |
• | $98 million loss on extinguishment of debt. See Note 9. Long-Term Debt. |
Fourth quarter 20172018 included the following:
$270a $1.3 billion goodwill impairment charge and $38 million deferred tax benefit, net, related to changes in federal income tax regulations; and
| |
• | $334 million gain on sale of mineral and royalty assets. See Note 5. Acquisitions and Divestitures.asset impairment expense. See Note 10. Impairments. |
(3) The sum of the individual quarterly earningsincome (loss) may not agree with year-to-date earningsincome (loss) as each quarterly computation is based on the earningsincome (loss) for the individual quarter as reported with rounding applied.
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“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, 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 of the end of the period covered by this Annual Report on Form 10-K. Based upon their evaluation, they have concluded that our disclosure controls and procedures were effective and provide an effective as of December 31, 2018.2019.
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
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
Effective, February 15, 2019, the Board of Directors of Noble Energy, Inc. (the “Company”) approved the amendment and restatement of the Company’s By-Laws (“By-Laws”). The revision to the By-Laws included an amendment to Article III, Section 1(b) to allow for a Lead Independent Director, who attains the age of 72 as of the next annual meeting succeeding such person’s 72nd birthday, to be eligible to stand for election as a director for one additional year, but ineligible to be appointed as the lead independent director.
The foregoing description of the amendment to the By-Laws is qualified in its entirety by reference to the full text of the By-Laws, a copy of which is filed as Exhibit 3.2 to this Annual Report on Form 10-K and incorporated herein by reference.None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
The information required by this item is incorporated herein by reference to the 20192020 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2018.2019.
Item 11. Executive Compensation
The information required by this item is incorporated herein by reference to the 20192020 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2018.2019.
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 20192020 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2018.2019.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this item is incorporated herein by reference to the 20192020 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2018.2019.
Item 14. Principal Accounting Fees and Services
The information required by this item is incorporated herein by reference to the 20192020 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2018.2019.
PART IV
Item 15. Exhibits, Financial Statement Schedules
| |
| (a) | The following documents are filed as a part of this report: |
| |
| (1) | Financial Statements: The consolidated financial statements and related notes, together with the reports of KPMG LLP, Independent Registered Public Accounting Firm, appear in Part II, Item 8, Financial Statements and Supplementary Data, of this Form 10-K. |
| |
| (2) | Financial Statement Schedules: All schedules for which provision is made in the applicable accounting regulations of the SEC are not required under the related instruction or are inapplicable and, therefore, have been omitted. |
| |
| (3) | Exhibits: The exhibits listed below on the Index to Exhibits are filed or incorporated by reference as part of this Form 10-K. |
INDEX TO 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) filedon January 17, 2017 (File No. 001-07964) and incorporated herein by reference). |
| 2.2 | — | |
2.3 | — | |
2.4 | — | |
| 3.1 | — | |
| 3.2 | — | |
| 3.3 | — | |
| 3.4 | — | |
| 4.1 | — | |
| 4.2 | — | |
4.24.3 | — | |
4.3 | —
| |
| 4.4 | —
| |
| 4.5 | — | |
| 4.6 | —
| Sixth Supplemental Indenture dated as of July 29, 2015, to Indenture dated as of February 27, 2009 between Noble Energy, Inc. and Wells Fargo Bank, National Association, as Trustee, relating the Registrant's 5.625% Notes due 2021, 5.875% Senior Notes due 2022 and 5.875% Notes due 2024 (including the forms of 2021 Notes, 2022 Notes and 2024 Notes) (filed as Exhibit 4.2 to the Registrant's Current Report on Form 8-K (Date of Report: July 29, 2015) filed July 31, 2015 (File No. 001-07964) and incorporated herein by reference). |
4.7 | — | |
Table of Contents| 4.7 | — |
| | | | | 4.8 | — | Indenture dated as of October 14, 1993 between the Registrant and US Trust Company of Texas, N.A., as Trustee, relating to the Registrant’s 7.25% Notes Due 2023 (including the form of 2023 Notes) (filed in paper with the SEC as Exhibit 4.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1993 on November 12, 1993 (File No. 001-07964) and incorporated herein by reference). | | 4.9 | — | |
| | | | | 4.10 | — | | | 4.11 | — | | | 10.1 | — | Credit Agreement, dated October 14, 2011, among Noble Energy, Inc., JPMorgan Chase Bank, N.A., as administrative agent, Citibank N.A., as syndication agent, Bank of America, N.A., Mizuho Corporate Bank, LTD., and Morgan Stanley MUFG Loan Partners, LLC, as documentation agents, and certain other commercial lending institutions named therein (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Report: October 14, 2011) filedon October 18, 2011 (File No. 001-07964) and incorporated herein by reference). | | 10.2 | — | Commitment Increase Agreement (Existing Lenders) dated September 28, 2012, among Noble Energy, Inc., JPMorgan Chase Bank, N.A., as administrative agent, and certain other commercial lending institutions party thereto (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Report: September 28, 2012), filedon October 2, 2012 (File No. 001-07964) and incorporated herein by reference). | | 10.3 | — | Commitment Increase Agreement (New Lenders) dated September 28, 2012, among Noble Energy, Inc., JPMorgan Chase Bank, N.A., as administrative agent, and certain other commercial lending institutions party thereto (filed as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K (Date of Report: September 28, 2012), filedon October 2, 2012 (File No. 001-07964) and incorporated herein by reference). | | 10.4 | — | First Amendment to Credit Agreement, dated October 3, 2013, by and among Noble Energy, Inc., NBL International Finance B.V., JPMorgan Chase Bank, N.A., as administrative agent, Citibank N.A., as syndication agent, and Bank of America, N.A., Bank of Tokyo-Mitsubishi UFJ, Ltd., Mizuho Bank, Ltd. and DNB Bank ASA, New York Branch as documentation agents, and the other commercial lending institutions party thereto (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Report: October 3, 2013) filedon October 9, 2013 (File No. 001-07964) and incorporated herein by reference). | | 10.5 | — | Second Amendment to Credit Agreement, dated August 27, 2015, by and among Noble Energy, Inc., JPMorgan Chase Bank, N.A., as administrative agent, Citibank N.A., as syndication agent, and Bank of America, N.A., Bank of Tokyo-Mitsubishi UFJ, Ltd., Mizuho Bank, Ltd. and DNB Bank ASA, New York Branch as documentation agents, and the other commercial lending institutions party thereto (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Report: August 27, 2015) filedon August 31, 2015 (File No. 001-07964) and incorporated herein by reference). | | 10.6 | — | Third Amendment to Credit Agreement, dated March 9, 2018, by and among Noble Energy, Inc., JPMorgan Chase Bank, N.A., as administrative agent, Citibank N.A., as syndication agent, and Bank of America, N.A., Bank of Tokyo-Mitsubishi UFJ, Ltd., Mizuho Bank, Ltd., and DNB Bank ASA, New York Branch as documentation agents, and the other commercial lending institutions party thereto (filed as Exhibit 10.1 to the Registrant's Current Report on Form 8-K (Date of Report: March 9, 2018) filedon March 12, 2018 (File No. 001-07964) and incorporated herein by reference). | | 10.7* | — | | | 10.8* | — | | 10.9*
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| | | | | 10.10* | — | Form of Indemnity Agreement entered into between the Registrant and each of the Registrant’s directors and bylaw officers (filed in paper with the SEC as Exhibit 10.18 to the Registrant’s Annual Report on Form 10-K405 for the year ended December 31, 1995 on March 25, 1996 (File No. 001-07964) and incorporated herein by reference). | | 10.11* | — | | | 10.12* | — | |
| | | | | 10.13* | — | | | 10.14* | — | | | 10.15* | — | | | 10.16* | — | | | 10.17* | — | | | 10.18* | — | | | 10.19* | — | | | 10.20* | — | | | 10.21* | — | | | 10.22* | — | | | 10.23* | — | | | 10.24* | — | | | 10.25* | — | | | 10.26* | — | | | 10.27* | — | |
| | | | | 10.28* | — | | | 10.29* | — | | | 10.30* | — | | | 10.31* | | |
| | | | | 10.32* | — | | 10.32*10.33* | — | | 10.33*10.34* | — | | 10.34*10.35* | — | | 10.35*10.36* | — | | 10.36*10.37* | — | | 10.37*10.38* | — | | 10.38*10.39* | — | | | 10.40* | — | | | 10.41* | — | | | 10.42* | — | | | 10.43* | — | | | 10.44* | — | | 10.39*10.45*
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| — | | 10.47*
| — | | 10.48*
| — | | | 10.49* | — | | 10.40*10.50* | — | |
10.41* | | | | | 10.51* | — | | 10.42*10.52* | — | | 10.43*10.53* | — | | 10.44*10.54* | — | | 10.45*10.55* | — | | 10.46*10.56* | — | |
| | | | 10.47*10.57* | — | | 10.48*10.58* | — | | 10.4910.59 | — | | 10.5010.60 | — | | 10.5210.61 | — | Support Agreement, dated as of January 13, 2017, by and among certain stockholders affiliated with Ares Management, LLC, Noble Energy, Inc., and solely for certain purposes specified therein, Clayton Williams Energy, Inc. (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Report: January 13, 2017) filedon January 17, 2017 (File No. 001-07964) and incorporated herein by reference). | 10.5310.62 | — | Agreement Not to Dissent, dated as of January 13, 2017, by and among Clayton W. Williams, Jr., Noble
Energy, Inc., and solely for certain purposes specified therein, Clayton Williams Energy, Inc. (filed as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K (Date of Report: January 13, 2017) filedon January 17, 2017 (File No. 001-07964) and incorporated herein by reference). | 10.5410.63 | — | Agreement Not to Dissent, dated as of January 13, 2017, by and among The Williams Children’s Partnership, Ltd., Noble Energy, Inc., and solely for certain purposes specified therein, Clayton Williams Energy, Inc. (filed as Exhibit 10.3 to the Registrant’s Current Report on Form 8-K (Date of Report: January 13, 2017) filedon January 17, 2017 (File No. 001-07964) and incorporated herein by reference). | 10.55† | — | | 10.5610.64 | — | | 10.57*10.65*
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| | | 21.1 | — | | | 23.1 | — | | | 23.2 | — | | | 31.1 | — | |
| | | | | 31.2 | — | | | 32.1 | — | | | 32.2 | — | | | 99.1 | — | | 101.INS101 | — | XBRL Instance DocumentThe following materials from the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2019 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Statements of Operations and Comprehensive Income (Loss); (ii) Consolidated Balance Sheets; (iii) Consolidated Statements of Cash Flows; (iv) Consolidated Statements of Equity; and (v) Notes to Consolidated Financial Statements. | 101.SCH104 | — | 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 DocumentCover Page Interactive Data File (formatted in iXBRL and contained in Exhibit 101). |
| | | | * | 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. | † | Confidential treatment granted under Rule 24b-2 as to certain portions of this exhibit, which are omitted and filed separately with the Commission. |
Item 16. Form 10-K Summary See None.
GLOSSARY In this report, the following abbreviations are used: | | | | | Bbl | | Barrel | | BBoe | | Billion barrels oil equivalent | | Bcf | | Billion cubic feet | | Bcf/d | | Billion cubic feet per day | | BCM | | Billion cubic meters | | BOE | | Barrels oil equivalent. Natural gas is converted on the basis of six Mcf of gas per one barrel of crude oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given commodity price disparities, the price for a barrel of crude oil equivalent for natural gas is significantly less than the price for a barrel of crude oil. The price for a barrel of NGL is also less than the price for a barrel of crude oil. | | Boe/d | | Barrels oil equivalent per day | | Btu | | British thermal unit | | FPSO | | Floating production, storage and offloading vessel | | GHG | | Greenhouse gas emissions | | GSPA | | Gas Sales Purchase Agreement | | HH | | Henry Hub index | | IDP | | Integrated Development Plan | | LNG | | Liquefied natural gas | | LPG | | Liquefied petroleum gas | | MBbl/d | | Thousand barrels per day | | MBoe/d | | Thousand barrels oil equivalent per day | | Mcf | | Thousand cubic feet | | MMBbls | | Million barrels | | MMBoe | | Million barrels oil equivalent | | MMBtu | | Million British thermal units | | MMBtu/d | | Million British thermal units per day | | MMcf/d | | Million cubic feet per day | | MMcfe/d | | Million cubic feet equivalent per day | | MMgal | | Million gallons | | Mt | | Metric ton | | Mt/d | | Metric tons per day | | NGLs | | Natural gas liquids | | NYMEX | | The New York Mercantile Exchange | | OPEC | | The Organization of Petroleum Exporting Countries | | PSC | | Production sharing contract | | Tcf | | Trillion cubic feet | | US GAAP | | United States generally accepted accounting principles | | WTI | | West Texas Intermediate index |
SIGNATURES 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. | | | | | | | NOBLE ENERGY, INC. | | | | (Registrant) | | | | | | Date: | February 19, 201912, 2020 | By: /s/ David L. Stover | | | | David L. Stover, | | | | Chairman of the Board and Chief Executive Officer | | | | | | Date: | February 19, 201912, 2020 | By: /s/ Kenneth M. Fisher | | | | Kenneth M. Fisher, | | | | Executive Vice President, Chief Financial Officer | | | | | | Date: | February 19, 201912, 2020 | By: /s/ Dustin A. Hatley | | | | Dustin A. Hatley, | | | | Vice President, Chief Accounting Officer and Controller |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. | | | | | | | Signature | | Capacity in which signed | | Date | | | | | | | | /s/ David L. Stover | | Chairman of the Board and Chief Executive Officer | | February 19, 201912, 2020 | | David L. Stover | | (Principal Executive Officer) | | | | | | | | | | /s/ Kenneth M. Fisher | | Executive Vice President, Chief Financial Officer | | February 19, 201912, 2020 | | Kenneth M. Fisher | | (Principal Financial Officer) | | | | | | | | | | /s/ Dustin A. Hatley | | Vice President, Chief Accounting Officer and Controller | | February 19, 201912, 2020 | | Dustin A. Hatley | | (Principal Accounting Officer) | | | | | | | | | | /s/ Jeffrey L. Berenson | | Director | | February 19, 201912, 2020 | | Jeffrey L. Berenson | | | | | | | | | | | | /s/ Michael A. Cawley | | Director | | February 19, 201912, 2020 | | Michael A. Cawley | | | | | | | | | | /s/ Edward F. Cox | | Director | | February 19, 2019 | Edward F. Cox | | | | | | | | | | | | /s/ James E. Craddock | | Director | | February 19, 201912, 2020 | | James E. Craddock | | | | | | | | | | | | /s/ Barbara J. Duganier | | Director | | February 19, 201912, 2020 | | Barbara J. Duganier | | | | | | | | | | | | /s/ Thomas J. Edelman | | Director | | February 19, 201912, 2020 | | Thomas J. Edelman | | | | | | | | | | | | /s/ Holli C. Ladhani | | Director | | February 19, 201912, 2020 | | Holli C. Ladhani | | | | | | | | | | | | /s/ Scott D. Urban | | Director | | February 19, 201912, 2020 | | Scott D. Urban | | | | | | | | | | | | /s/ William T. Van Kleef | | Director | | February 19, 201912, 2020 | | William T. Van Kleef | | | | | | | | | | | /s/ Martha B. Wyrsch | | Director | | February 12, 2020 | | Martha B. Wyrsch | | | | |
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