UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
ýANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 20172018
or
oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period fromto
Commission file number: 001-07964
NOBLE ENERGY, INC.INC.
(Exact name of registrant as specified in its charter)
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| | |
| 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)
Securities registered pursuant to Section 12(b) of the Act:
|
| | |
| Title of each class | | Name of each exchange on which registered |
| Common Stock, $0.01 par value | | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ý Yes o 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 o No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). ý Yes o 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 definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one): |
| | | | |
Large accelerated filer x | Accelerated filer o | Non-accelerated filer o | Smaller reporting company o | Emerging growth company o |
| (Do not check if a smaller reporting company) | |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 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, 2017: $13.82018: $17.0 billion.
Number of shares of Common Stock outstanding as of December 31, 2017: 486,902,907.2018: 477,643,425.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive proxy statement for the 20182019 Annual Meeting of StockholdersShareholders to be held on April 24, 2018,23, 2019, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2017,2018, 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;
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 liquids (NGLs) resources;
anticipated trends in our business;
market conditions in the oil and gas industry;
the impact of governmental fiscal regulation, including United States (US) federal, state, local, and foreign host government tax regulations, and/orfiscal policies and terms, suchas well as that involving the protection of the environment or marketing of production as well asand other regulations;
our ability to make and integrate acquisitions;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: NBL) is an independent crude oil and natural gas exploration and production company with a diversified high-quality portfolio spanning three continents.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 a Delaware corporation, incorporated in 1969,guided by its values, its commitment to safety, and has been publicly tradedrespect for stakeholders, communities and the environment. For more information on how the New York Stock Exchange (NYSE) since 1980. We have a unique history of growth, evolving from a regional crude oil and natural gas producer to a global exploration and production company included in the Standard & Poor's 500 (S&P 500).
Our purpose, Company fulfills its purpose: Energizing the World, Bettering People's Lives®, reflects our commitment to find and deliver affordable energy through crude oil, natural gas and NGL exploration and production while living our commitment to contribute to the betterment of people's lives in the communities in which we operate. We strive to build trust through stakeholder engagement, actvisit https://www.nblenergy.com. Information on our values, providewebsite is not incorporated by reference into, and does not constitute a safe work environment, respect our environment and care for our employees and the communities where we operate.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, and NGLs.gas. In particular, our business is focused on both US onshore unconventional basins and certain global offshore conventional basins.basins in the Eastern Mediterranean and off the west coast of Africa. In US onshore unconventional basins, we have demonstrated competence in applyingour ability to apply geological, drilling, completion, and midstream design and operational expertise. In US onshore, we typically apply a major project development concept to an unconventional basin by utilizingutilize an Integrated Development Plan (IDP) approach.which applies a major project development approach to an unconventional basin. In the global offshore, we have had notable exploration and major project successes, over the past twelve years, which have led to production from numerous offshore major development projects which haveand provided long-lived cash flows to our business.
ApproximatelyCapital Program Looking ahead, approximately 70% of our 20182019 capital program (excluding capital funded by Noble Midstream Partners 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, Delaware Basin, and Eagle Ford Shale. Eastern Mediterranean capital expenditures, including initial developmentremaining costs associated with the Leviathan project, represent more than 25%approximately 20% of the total. The remaining portion of our 2018the capital program is designated for exploration for lease acquisition, seismicthe drilling of a crude oil development well in West Africa, and other exploration and corporate activities. See 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 supportthe business of futurecrude oil and natural gas acquisition and exploration, prospects for potential development, post 2020,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 corporate activities.financially attractive midstream projects, with current focus areas being the DJ and Delaware Basins. See Item 8. Financial Statements and Supplementary Data – Note 3. Segment Information. In addition,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 majoritypast 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 assets are held by production, which allows for further investmentcapital program, strengthen our liquidity and financial flexibility. Occasionalreturn value to shareholders through the share repurchase program. We expect active portfolio management to continue as an element in our strategic program.
Periodically, we may also engage in acquisitions of producingadditional crude oil or non-producingnatural gas properties combined withand related assets through either direct acquisitions of the periodic divestmentassets or acquisitions of assets, have allowed us to pursue our objectiveentities that own the assets. For example, in January 2018, Noble Midstream Partners LP (Noble Midstream Partners) acquired an interest in Black Diamond (defined below) which completed the acquisition of a well-positionedSaddle Butte Rockies Midstream, LLC and diversified portfolio to maximize strategic value.affiliates (collectively, Saddle Butte), and in 2017 we completed the acquisition (Clayton Williams Energy Acquisition) of Clayton Williams Energy, Inc. (Clayton Williams Energy). See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources and Item 8. Financial Statements and Supplementary Data – Note 5. Acquisitions and Divestitures. Oil and Gas Properties and ActivitiesWe search for crude oil and natural gas properties onshore and offshore, and seek to acquire exploration rights and conduct exploration activities in areas of interest. Our activities include geophysical and geological evaluation; analysis of commercial, regulatory and political risks; and exploratory and development drilling leading to production, where appropriate.
Our current portfolio consists primarily of interests in developed and undeveloped crude oil and natural gas leases and concessions. These properties contribute all of our crude oil, NGL and natural gas and NGL production, provide continualadditional investment opportunities in proved areas, and offer further exploration opportunities. Our new venture areas provide frontier exploration opportunities, which may result in the establishment of new operational areas in the future. We also own or invest in midstream assets primarily used in the gathering, processing and transportation of our US onshore production. See Midstream -– Properties and Activities, below..
The map below illustrates the locations of our significant crude oil and natural gas exploration and production activities:
Reportable Segments We manage our operations by geographic region and the nature of the products and services we offer. Our reportable segments include: United States (US onshore and Gulf of Mexico); Eastern Mediterranean (Israel and Cyprus); West Africa (Equatorial Guinea, Cameroon and Gabon); Other International (Newfoundland, Suriname, and other new ventures); and Midstream.
The geographical reportable segments are in the business of crude oil and natural gas exploration, development, production, and acquisition (Oil and Gas Exploration and Production, or E&P). The Midstream reportable segment owns, operates, develops and acquires domestic midstream infrastructure assets with current focus areas being the DJ and Delaware Basins. Expenses related to debt, headquarters depreciation and corporate general and administrative cost are recorded at the corporate level. See Item 8. Financial Statements and Supplementary Data – Note 14. Segment Information.Development ActivitiesOur development projects have resulted from both exploration success as well as periodic strategic acquisitions.leasing activities which provide entrance to low cost assets. These projects provide opportunities for growth at attractive financial returns. Each project progresses, as appropriate, through the various development phases including appraisal, engineering and design, development drilling, construction and production. While development projects require significant capital investments, typically over a multi-year period, they are expected to offer sustained cash flows while onduring 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 accommodate a flexible capital investment program that can be varied in response to changes in the commodity price environment. We continue to enhance project performance in these areas through design, technology and operational efficiencies.
Offshore, we engage in long-cycle development projects, such as progressing the first phase of development at the Leviathan natural gas field, offshore Israel, the largest natural gas discovery in our history.history, and advancing Aseng crude oil development and Alen natural gas monetization in West Africa. Our development activities are discussed in more detail in the sections below.
Divestiture and Acquisition ActivitiesWe maintain an ongoing portfolio management program. Accordingly, we may periodically divest assets through asset or equity sales, exchanges or other transactions. During 2017, we closed several transformative portfolio transactions, demonstrating our continued focus on enhancing profit margins and company returns. We generated cash of $2.1 billion from asset sales, including divestiture of the Marcellus Shale upstream assets, as well as other non-strategic US onshore assets. Periodically, we may also engage in acquisitions of additional crude oil or natural gas properties and related assets through either direct acquisitions of the assets or acquisitions of entities that own the assets. For example, we completed the acquisition (Clayton Williams Energy Acquisition) of Clayton Williams Energy, Inc. (Clayton Williams Energy) in 2017 and the merger (Rosetta Merger) of Rosetta Resources Inc (Rosetta) in 2015. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources, Item 8. Financial Statements and Supplementary Data - Note 3. Clayton Williams Energy Acquisition, and Item 8. Financial Statements and Supplementary Data – Note 4. Acquisitions, Divestitures and Merger.Exploration Activities We primarily focus on organic growth from exploration and development drilling activities, concentrating on existing basins or plays where we believe we have strategic competitive advantages or in new basins with attractive geological potential and the opportunity for attractivecompetitive 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 Gulf of Mexico, the Levant Basin offshore Eastern Mediterranean and the Douala Basin offshore West Africa, resulting in the successful completion of numerous major development projects. In 2017,2018, we performedconducted limited exploration activities dueas we focused our capital expenditures on the development of the Leviathan field and US onshore assets.
Proved Reserves Disclosures
Proved Oil and Gas ReservesProved reserves at December 31, 20172018 were as follows: | | | | | December 31, 2017 | |
| | | Proved Reserves | | | | | | | | | | | |
| | | Crude Oil and Condensate | | NGLs | | Natural Gas | | Total | | Crude Oil and Condensate | | NGLs | | Natural Gas | | Total |
| Reserves Category | | (MMBbls) | | (MMBbls) | | (Bcf) | | (MMBoe) (1) | | (MMBbls) | | (MMBbls) | | (Bcf) | | (MMBoe)(1) | | (Percent) |
| Proved Developed | | | | | | | | | | | | | | | | | | |
| United States | | 176 |
| | 119 |
| | 983 |
| | 458 |
| | 165 |
| | 121 |
| | 929 |
| | 442 |
| | 59 | % |
| Israel | | 3 |
| | — |
| | 1,793 |
| | 302 |
| | 2 |
| | — |
| | 1,295 |
| | 218 |
| | 29 | % |
Equatorial Guinea
| | 29 |
| | 11 |
| | 411 |
| | 108 |
| | 26 |
| | 9 |
| | 355 |
| | 94 |
| | 12 | % |
| Total Proved Developed Reserves | | 208 |
| | 130 |
| | 3,187 |
| | 868 |
| | 193 |
| | 130 |
| | 2,579 |
| | 754 |
| | 100 | % |
| Proved Undeveloped | | |
| | | | |
| | |
| | |
| | | | |
| | |
| | |
| United States | | 243 |
| | 99 |
| | 838 |
| | 482 |
| | 255 |
| | 136 |
| | 1,015 |
| | 560 |
| | 48 | % |
| Israel | | 6 |
| | — |
| | 3,655 |
| | 615 |
| | 6 |
| | — |
| | 3,635 |
| | 612 |
| | 52 | % |
| Equatorial Guinea | | | 3 |
| | — |
| | 2 |
| | 3 |
| | — | % |
| Total Proved Undeveloped Reserves | | 249 |
| | 99 |
| | 4,493 |
| | 1,097 |
| | 264 |
| | 136 |
| | 4,652 |
| | 1,175 |
| | 100 | % |
| Total Proved Reserves | | 457 |
| | 229 |
| | 7,680 |
| | 1,965 |
| | 457 |
| | 266 |
| | 7,231 |
| | 1,929 |
| | |
(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 as compared with 1,437 MMBoe as of December 31, 2016. Changes included the following:
revisions of 135 MMBoe, including positive revisions of 105 MMBoe driven by performance related to the US onshore horizontal drilling programs and offshore Israel associated with the enhanced geologic modeling across the Tamar reservoir, as well as an increase of 30 MMBoe driven by positive price revisions;
extensions, discoveries and other additions of 736 MMboe, including additions of 551 MMBoe related to the sanction of the first phase of development of the Leviathan natural gas project, as well as extensions of 185 MMBoe related to US onshore horizontal drilling programs due to successful expansion of our extended reach lateral well programs;
acquisition of 57 MMBoe primarily related to the Clayton Williams Energy Acquisition;
offset by:
production volumes of 139 MMBoe; and
divestiture of reserves of 261 MMBoe, primarily due to the Marcellus Shale upstream divestiture and other smaller US onshore divestitures.
2017. Our proved reserves are 48%52% US and 52%48% international, and the commodity mix is 35%37% global liquids (crude oil and NGLs), 50%46% international natural gas and 15%17% US natural gas.
See Proved Reserves Disclosures, below,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 |
|
for further discussion.Proved Undeveloped Reserves (PUDs) As of December 31, 2018, our PUDs totaled 1,175 MMBoe, or 61% of proved reserves. Changes in PUDs were as follows for the year ended December 31, 2018. |
| | | | | | | | | | | | |
| (MMBoe) | | United States | | Israel | | Equatorial Guinea | | Total |
| Proved Undeveloped Reserves, Beginning of Year | | 482 |
| | 615 |
| | — |
| | 1,097 |
|
| Revisions of Previous Estimates | | (23 | ) | | — |
| | — |
| | (23 | ) |
| Extensions, Discoveries and Other Additions | | 181 |
| | 12 |
| | 3 |
| | 196 |
|
| Sale of Minerals in Place | | — |
| | (15 | ) | | — |
| | (15 | ) |
| Conversion to Proved Developed | | (80 | ) | | — |
| | — |
| | (80 | ) |
| Proved Undeveloped Reserves, End of Year | | 560 |
| | 612 |
| | 3 |
| | 1,175 |
|
Revisions of Previous Estimates 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; |
the Delaware Basin included a negative 25 MMBoe non-price revision primarily due to changes in expected recoveries and higher operating and capital costs; and
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.
Extensions, Discoveries and Other Additions Extensions of proved reserves were primarily due to drilling plans for new wells, of which94 MMBoe, 69 MMBoe, 18 MMBoe, 12 MMBoe and 3 MMBoe were in the DJ Basin, Delaware Basin, Eagle Ford Shale, Tamar field and Equatorial Guinea, respectively.
US PUDs Locations During the year, we converted 80 MMBoe of our US PUDs, or 17% of our US PUDs beginning balance, 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 Locations 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 the Tamar Southwest field are expected to be converted to proved developed reserves prior to the end of 2020 as contemplated in our long-range development plan. Initial production 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 companies 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%. As of December 31, 2018, we had no PUDs with a negative present worth when discounted at 10%.
Internal Controls Over Reserves EstimatesOur 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 planning and reserves departments. He is the technical person primarily responsible for overseeing the preparation of our reserves estimates and the third-party audit of our reserves estimates. He has Bachelor of Science and Master of Science degrees in Petroleum Engineering and over 38 years of industry experience. Since 2008, 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 EstimationThe 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 2018, 2017, and 2016, we retained NSAI to perform audits of proved reserves. The reserves audit for 2018 included a detailed review of six of our major US onshore and international fields, which covered approximately 98% of total proved reserves.
In connection with the 2018 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, 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 DataSales volumes, price and cost data were as follows:
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| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 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 |
| | — |
|
| |
(3) | 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) | Volumes represent sales of condensate and liquefied petroleum gas (LPG) from the LPG plant in Equatorial Guinea. |
At December 31, 2018, our operated properties accounted for substantially all of our total production. Being the operator of a property improves our ability to directly influence production levels and the timing of projects, while also enhancing our control over operating expenses and capital expenditures.
Productive WellsThe number of productive crude oil and natural gas wells in which we held an interest at December 31, 2018 were as follows: |
| | | | | | | | | | | | | | | | | | |
| | | Crude Oil Wells | | Natural Gas Wells | | Total |
| | | Gross | | Net | | Gross | | Net | | Gross | | Net |
| United States | | 5,289 |
| | 4,781 |
| | 909 |
| | 842 |
| | 6,198 |
| | 5,623 |
|
| Israel | | — |
| | — |
| | 7 |
| | 2 |
| | 7 |
| | 2 |
|
| Equatorial Guinea | | 5 |
| | 2 |
| | 23 |
| | 8 |
| | 28 |
| | 10 |
|
| Total | | 5,294 |
| | 4,783 |
| | 939 |
| | 852 |
| | 6,233 |
| | 5,635 |
|
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 AcreageDeveloped and undeveloped acreage (including both leases and concessions) in which we held an interest at December 31, 2018 were as follows:
|
| | | | | | | | | | | | |
| | | Developed Acreage | | Undeveloped Acreage |
| (thousands of acres) | | Gross | | Net | | Gross | | Net |
| United States | | | | | | | | |
| Onshore | | 549 |
| | 449 |
| | 527 |
| | 384 |
|
| Offshore | | 14 |
| | 5 |
| | 6 |
| | 3 |
|
| Total United States | | 563 |
| | 454 |
| | 533 |
| | 387 |
|
| International | | |
| | |
| | |
| | |
|
Israel (1) | | 185 |
| | 74 |
| | 284 |
| | 111 |
|
Equatorial Guinea | | 284 |
| | 118 |
| | 81 |
| | 30 |
|
| Newfoundland, Canada | | — |
| | — |
| | 2,332 |
| | 681 |
|
| Gabon | | — |
| | — |
| | 671 |
| | 403 |
|
| Cyprus | | — |
| | — |
| | 95 |
| | 33 |
|
| Cameroon | | — |
| | — |
| | 168 |
| | 168 |
|
| Total International | | 469 |
| | 192 |
| | 3,631 |
| | 1,426 |
|
| Total | | 1,032 |
| | 646 |
| | 4,164 |
| | 1,813 |
|
(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 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 expire in the next three years. As of December 31, 2018, there are no PUDs associated with this acreage.
Drilling ActivityThe results of crude oil and natural gas wells drilled and completed for each of the last three years were as follows: |
| | | | | | | | | | | | | | | | | | | | | |
| | | Net Exploratory Wells | | Net Development Wells | | |
| | | Productive | | Dry | | Total | | Productive | | Dry | | Total | | Total |
| Year Ended December 31, 2018 | | | | | | | | |
| | | | | | |
| United States | | — |
| | — |
| | — |
| | 203.0 |
| | — |
| | 203.0 |
| | 203.0 |
|
| Total | | — |
| | — |
| | — |
| | 203.0 |
| | — |
| | 203.0 |
| | 203.0 |
|
| Year Ended December 31, 2017 | | | | | | | | |
| | | | | | |
| United States | | — |
| | — |
| | — |
| | 185.3 |
| | — |
| | 185.3 |
| | 185.3 |
|
| Israel | | — |
| | — |
| | — |
| | 0.3 |
| | — |
| | 0.3 |
| | 0.3 |
|
| Suriname | | — |
| | 0.2 |
| | 0.2 |
| | — |
| | — |
| | — |
| | 0.2 |
|
| Total | | — |
| | 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, 2018 were as follows:
|
| | | | | | | | | | | | | | | | | | |
| | | Exploratory(1) | | Development(1) | | Total |
| | | Gross | | Net | | Gross | | Net | | Gross | | Net |
| United States | | — |
| | — |
| | 114.0 |
| | 107.1 |
| | 114.0 |
| | 107.1 |
|
Israel (2) | | — |
| | — |
| | 4.0 |
| | 1.6 |
| | 4.0 |
| | 1.6 |
|
| Total | | — |
| | — |
| | 118.0 |
| | 108.7 |
| | 118.0 |
| | 108.7 |
|
| |
(1) | 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 and NGL exploration and development activities throughout US onshore since 1932 and in the Gulf of Mexico since 1968.1932. US operations accounted for 72%74% of 20172018 total consolidated sales volumes and 48%52% of total proved reserves at December 31, 2017.2018. Approximately 45%42% of the proved reserves in the US isare crude oil and condensate, 32% isare natural gas and 23% is26% are NGLs.
Sales volumes and proved reserves estimates for our US operating areas were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, 2017 | | December 31, 2017 |
| | | Sales Volumes | | Proved Reserves |
| | | Crude Oil & Condensate | | NGLs | | Natural
Gas | | Total | | Crude Oil & Condensate | | NGLs | | Natural
Gas | | Total |
| | | (MBbl/d) | | (MBbl/d) | | (MMcf/d) | | (MBoe/d) | | (MMBbls) | | (MMBbls) | | (Bcf) | | (MMBoe) |
| DJ Basin | | 59 |
| | 19 |
| | 193 |
| | 110 |
| | 203 |
| | 99 |
| | 1,094 |
| | 484 |
|
| Delaware Basin | | 17 |
| | 4 |
| | 24 |
| | 26 |
| | 166 |
| | 38 |
| | 199 |
| | 238 |
|
| Eagle Ford Shale | | 11 |
| | 28 |
| | 186 |
| | 70 |
| | 29 |
| | 79 |
| | 501 |
| | 191 |
|
Marcellus Shale (1) | | 1 |
| | 5 |
| | 174 |
| | 34 |
| | — |
| | — |
| | — |
| | — |
|
| Gulf of Mexico | | 21 |
| | 2 |
| | 21 |
| | 26 |
| | 18 |
| | 2 |
| | 21 |
| | 23 |
|
| Other US Onshore | | 2 |
| | — |
| | 9 |
| | 4 |
| | 3 |
| | — |
| | 6 |
| | 4 |
|
| Total | | 111 |
| | 58 |
| | 607 |
| | 270 |
| | 419 |
| | 218 |
| | 1,821 |
| | 940 |
|
(1) We divested our Marcellus Shale upstream assets in In second quarter 2017.2018, we exited the Gulf of Mexico through sale of our properties.
Wells completed in 2017 and productive wells at December 31, 2017 for our US operating areas were as follows:
|
| | | | | | |
| | | Year Ended December 31, 2017 | | December 31, 2017 |
| | | Gross Wells Completed or Participated in | | Gross Productive Wells |
| DJ Basin | | 138 |
| | 6,226 |
|
| Delaware Basin | | 75 |
| | 1,898 |
|
| Eagle Ford Shale | | 47 |
| | 344 |
|
| Gulf of Mexico | | — |
| | 14 |
|
| Other US Onshore | | 12 |
| | 1 |
|
| Total | | 272 |
| | 8,483 |
|
US Onshore
Our US onshore operations are located in proven basins with long-life production profiles. These assets provide low production-risk drilling opportunities in liquids-rich areas that offer predictable and long-term production and cash flow growth at attractive financial returns. In addition, we evaluate and consider other US onshore new venture prospects to complement our portfolio. Locations of our US onshore operations as of December 31, 20172018 are shown on the map below:
DJ Basin Our operations in the DJ Basin represent a key asset within our US onshore asset portfolio. As of December 31, 2018, 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 2017,2018, we focused our drilling and development activity in theall three of our main IDP areas, including Mustang, Wells Ranch and East Pony areas that produce a high oil mix. The IDP concept allows us to consolidate processing and handling infrastructure across large areas (typically 30,000 to 80,000 acres).Pony. Our IDP approach has provided an opportunity to efficiently and economically supportdrive production growth by leveraging infrastructure such asfor crude oil, natural gas, oil and water, including both fresh and produced water assets.
2017 Activity Operationally, our focus on drilling longer laterals and obtaining better results from enhanced completions has led to stronger new well performance. Coupled with expansionIn 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 and Mustang IDP areas, we executed acreage trades which add to our contiguous acreage positions and further allow us to control the pace of midstream infrastructuredevelopment and execution of synergies as well as prudent management of costs, we are delivering enhanced profit margin returns.capital investment. During the year, we completed 103 horizontal99 wells and 101 wells initiated production.commenced production on 106 wells. We also participated in approximately 35two non-operated development wells during 2017.
2018. As
partwe continue to manage our portfolio, we executed and closed the sale of
ongoing portfolio management, we entered into an agreement to divest approximately 30,200 net acres, the majority of which were undeveloped,certain assets in the Greeley Crescent area
of Weld County, Colorado for $608 million. We receivedin 2018 receiving aggregate proceeds of
$568 million at closing$68 million. See Item 8. Financial Statements and expectSupplementary 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 receivecontrol the remaining proceeds in mid-2018.pace of development and to utilize shared facilities and infrastructure, which is expected to reduce trucking and surface access. As part of the transaction, all ofCDP, the acreage inpermitting process has been clarified and the Greeley Crescent Bronco IDP remains subject to dedications to Noble Midstream Partners LP (Noble Midstream Partners)expiration term for crude oil gathering, and produced and fresh water services.
Since 2015, we have been working with the State of Colorado to improve emission control systems as required under a joint consent decree (Consent Decree). Overall compliance with the Consent Decree has resulted in the temporary shut-in and permanent plugging and abandonment of certain wells, the majority of which are vertical, and associated tank batteries. Costs associated with these abandonment activities will be incurredawarded permits is six years, an increase from the previous two years. We have received permits for over several years.
We exited 2017 with one drilling rig and intend to increase to two rigs in 2018. Our current 2018 development program contemplates expansion into400 locations across the Mustang IDP area where we have a large, contiguous acreage position.area.
Delaware Basin (Permian Basin)Our Delaware Basin position was significantly transformed in 2017 with the closing of the Clayton Williams Energy Acquisition, on April 24, 2017, adding 71,000 highly contiguous net acres in the core of the Delaware Basin adjacent to our Reeves County holdings. We also executed strategic leasing initiatives and entered into a bolt-on acquisition, for $295 million, which closed in January 2017, adding additional production near our producing properties and increasing our
contiguous acreage position in the Reeves County area. As of December 31, 2017,2018, we held approximately 117,000108,000 net acres in the Delaware Basin.Basin and had proved reserves of 258 MMBoe. Total sales volumes for 2018 were 53 MBoe/d.
20172018 Activity In 2017,2018, we successfully integrated the Clayton Williams Energy assets and initiatedcontinued execution of the Delaware Basin IDP with a focus on long laterals,lateral length, pad drilling, multi-zone completions and infrastructure development. As demonstratedWe 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 facilities
(CGFs). In late 2018, we moderated our completion activity in the DJ Basin, our IDP approach provides an opportunitybasin to more efficientlyalign with economic and economically develop our acreage.available takeaway capacity.
We successfully transformed our 2017 development program's focus from a single well development approach to an IDP to capture the full resource potential for the Delaware Basin. This was achieved with eight pads that developed multiple zones within the Wolfcamp A formation zone, including two pads that successfully included the shallower 3rd Bone Springs zone. With successful wells in the deeper Wolfcamp zones, as well as expanded understanding of the resource potential and our IDP approach, we are well positioned to efficiently and economically develop our acreage over future years.
We began 2017 with three drilling rigs and exited the year with six drilling rigs. During the year, we completed 4570 wells and commenced production on 44 wells, of which 23 were multi-zone pads.72 wells. We also participated in approximately 3020 non-operated development wells during 2017.2018. In addition, we addedbegan flowing production to three newly constructed CGFs, an increase from two central gathering facilities (CGFs).CGFs in 2017, operated by Noble Midstream Partners.
ForWe utilize the Advantage Pipeline (defined 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 agreement which brings our crude oil to the Texas Gulf Coast. 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, 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 dedicated substantially all of our Delaware Basin acreage position in Reeves County, Texas to the EPIC Crude Oil Pipeline for firm transport of up to 100 MBbl/d, gross, of crude oil from the Delaware Basin to Corpus Christi, Texas, for a 10-year period beginning at pipeline start-up. EPIC announced that it will continue asset developmentprovide early access to oil pipeline transportation through long laterals, pad drilling, multi-zone developmentits 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 infrastructure build-out initiative that will include anattractive pipeline transport cost.
As part of the EPIC strategic relationship, in first quarter 2019, we assigned Noble Midstream Partners our option 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 three CGFs.sources of funding. See Item 8. Financial Statements and Supplementary Data – Note 5. Acquisitions and Divestitures. Eagle Ford Shale We holdAs of December 31, 2018, we held approximately 35,000 net acres located in the highly prolific liquids-rich area of the play, including producing assets in Webb and Dimmit counties.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 through testing varying clusters per stage, lateral lengths, and proppant quantities to increase investment efficiency. We have also focused on testing co-development of both the Upper and Lower Eagle Ford formation zones utilizing our IDP approach.zones.
20172018 Activity Our 20172018 capital program was primarily focused within Webb and Dimmit counties where we operated up to two drilling rigs, completed 47 horizontal wells and commenced production on 49 horizontal wells. All wells drilled during 2017 were on multi-well pads leveraging centralized infrastructure. We also sold certain assets located in Gonzales and DeWitt counties, where we had not engaged in drilling activities since the completion of the merger (Rosetta Merger) with Rosetta Resources Inc. (Rosetta) and received proceeds of $45 million.
We exited 2017 with a two rig drilling program. Our capital program in 2018 focuses on developing the Upper and Lower Eagle Ford formation zones withinwhere 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 area.which will provide separation and compression capabilities for our multi-well completion program which began in fourth quarter 2018 and will continue into 2019.
Marcellus Shale On June 28, 2017,Onshore Exploration Activity In 2018, we captured over 100,000 net acres through undeveloped leasehold acquisition activity in the US onshore. In 2019, we expect to perform additional geologic studies and conduct permitting activities.
US Offshore
In second quarter 2018, we closed the sale of the Marcellus Shale upstreamour Gulf of Mexico assets, receiving net proceeds of $1.0 billion$384 million and recorded a loss on sale of $2.38 billion.$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.
Gulf of MexicoLocations of our operations in the Gulf of Mexico as of December 31, 2017 are shown on the map below:
We have several producing fields and an inventory of identified prospects, which are a combination of both high impact subsalt prospects and smaller tie-back opportunities. These prospects are subject to an ongoing technical maturation process and may or may not emerge as drillable options.
We currently hold leases on approximately 63 deepwater blocks, representing approximately 52,000 net developed acres and approximately 171,000 net undeveloped acres. We are the operator on nearly 80% of our leases.
2017 Activity Our activity in 2017 primarily focused on optimizing production and progressing our Katmai project. See Offshore Producing Properties and Update to Gulf of Mexico Major Projects, below.
During 2017, we completed our geological evaluation of certain leases and determined that several leases, representing $60 million of undeveloped leasehold cost, should be impaired and expensed.
Offshore Producing Properties
Gunflint (Mississippi Canyon Block 948; 31% operated working interest) Gunflint is a 2008 crude oil discovery, utilizing a two-well subsea tieback to the Gulfstar 1 spar platform. Production commenced in July 2016 and the development contributed 7 MBoe/d of sales volumes in 2017.
Rio Grande Development including Big Bend (Mississippi Canyon Block 698; 54% operated working interest) and Dantzler (Mississippi Canyon Block 782; 45% operated working interest) The Rio Grande crude oil development project consists of a single producing well from Big Bend, a 2012 crude oil discovery, and two producing wells from Dantzler, a 2013 crude oil discovery, flowing to the Thunder Hawk platform for which we assumed operatorship in 2016. The Rio Grande development commenced production in October 2015 and contributed an average of 12 MBoe/d of sales volumes in 2017.
Galapagos Development Project including Isabela (Mississippi Canyon Block 562; 33.33% non-operated working interest), Santa Cruz (Mississippi Canyon Blocks 519/563; 23.25% operated working interest)and Santiago (Mississippi Canyon Block
519; 23.25% operated working interest) The Galapagos crude oil development project consists of Isabela, a 2007 discovery, Santa Cruz, a 2009 discovery, and Santiago, a 2011 discovery. The Galapagos development began producing in 2012 and is connected to existing infrastructure through subsea tiebacks. A well stimulation commenced in the fourth quarter of 2017 to enhance recovery. The Galapagos project contributed an average of 4 MBoe/d of sales volumes in 2017.
Swordfish (Viosca Knoll Blocks 917; 961 and 962; 85% operated working interest) Swordfish is a 2001 crude oil discovery and began producing in 2005. The Swordfish project currently includes two producing wells flowing to the Neptune Spar, our 100%-owned floating offshore production platform, and contributed an average of 3 MBoe/d of sales volumes in 2017. We currently plan to begin abandonment activities in 2019.
Ticonderoga (Green Canyon Block 768; 50% non-operated working interest) Ticonderoga is a 2004 crude oil discovery and began producing in 2006. The project currently includes two producing wells, which contributed an average of 1 MBoe/d of sales volumes in 2017. These properties are connected to existing infrastructure through subsea tiebacks.
Update to Gulf of Mexico Major Projects
Katmai (Green Canyon Block 40; 50% operated working interest) During 2014, we announced successful final well results at the Katmai exploratory well. Katmai was drilled to a total depth of 27,900 feet in 2,100 feet of water. Wireline logging data indicated a total of 154 net feet of crude oil pay discovered in multiple reservoirs, including 117 net feet in Middle Miocene and 37 net feet in Lower Miocene reservoirs. In 2016, we spud our Katmai 2 appraisal well (38% operated working interest), located in Green Canyon Block 39, and encountered high pressure in the untested fault block. In response, we temporarily abandoned the well and are assessing plans to complete appraisal as well as development scenarios for the Katmai project.
Troubadour (Mississippi Canyon Block 699; 60% operated working interest) Troubadour was a 2013 natural gas discovery. In 2017, we determined that the asset was impaired in the current forward outlook for natural gas prices and development scenarios, and charged $63 million to impairment of oil and gas properties and $5 million to undeveloped leasehold impairment expense.
International
Our international business focuses on offshore opportunities in a number of countries and diversifies our portfolio. Development projects in the Eastern Mediterranean and West Africa have contributed substantially to our production and cash flow growth over the last decade. Previous exploration successes in these areas have also identified additional multiple major development projects that have the potential to contribute to long-term production and cash flow growth in the future.
During 2017,2018, we progressed development of offshore Israel assets primarily through the continued development of Leviathan, where first natural gas sales are anticipated by completing the Tamar 8 development well and commencing drilling activities for the Leviathan 5 development well.end of 2019. In addition, we advanced our Eastern Mediterranean regional natural gas export opportunities by progressing multipleexecuting natural gas sales and purchase agreements (GSPAs). See Eastern Mediterranean (Israel for the Leviathan and Cyprus)Tamar fields, offshore Israel, and continue efforts to monetize our significant natural gas discoveries offshore West Africa (Equatorial Guinea, Cameroon and Gabon), below.Africa.
Operations in Equatorial Guinea, Cameroon, Gabon, Cyprus, and SurinameCyprus are conducted in accordance with the terms of Production Sharing Contracts (PSCs). Operations in Israel, Newfoundland (Canada) and other foreign locations are conducted in accordance with concession agreements, permits or licenses. See Item 1A. Risk Factors.
Sales volumes and proved reserves estimates for our international operating areas were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, 2017 | | December 31, 2017 |
| | | Sales Volumes | | Proved Reserves |
| | | Crude Oil & Condensate | | NGLs | | Natural Gas | | Total | | Crude Oil & Condensate | | NGLs | | Natural Gas (1) | | Total |
| | | (MBbl/d) | | (MBbl/d) | | (MMcf/d) | | (MBoe/d) | | (MMBbls) | | (MMBbls) | | (Bcf) | | (MMBoe) |
| International | | | | | | | | | | | | | | | | |
| Israel | | — |
| | — |
| | 272 |
| | 46 |
| | 9 |
| | — |
| | 5,448 |
| | 917 |
|
| Equatorial Guinea | | 18 |
| | — |
| | 239 |
| | 57 |
| | 29 |
| | 11 |
| | 411 |
| | 108 |
|
| Total International | | 18 |
| | — |
| | 511 |
| | 103 |
| | 38 |
| | 11 |
| | 5,859 |
| | 1,025 |
|
| Equity Investee | | 2 |
| | 6 |
| | — |
| | 8 |
| | — |
| | — |
| | — |
| | — |
|
| Total | | 20 |
| | 6 |
| | 511 |
| | 111 |
| | 38 |
| | 11 |
| | 5,859 |
| | 1,025 |
|
| Equity Investee Share of Methanol Sales (MMgal) | | 163 |
| | |
| | | | | | |
|
(1) Includes 3.3 Tcf proved undeveloped reserves related to initial Leviathan field development offshore Israel.
Wells completed in 2017 and productive wells at December 31, 2017 in our international operating areas were as follows:
|
| | | | | | |
| | | Year Ended December 31, 2017 | | December 31, 2017 |
| | | Gross Wells Completed or Participated in (1) | | Gross Productive Wells |
| International | | | | |
| Israel | | 1 |
| | 7 |
|
| Equatorial Guinea | | — |
| | 28 |
|
| Total International | | 1 |
| | 35 |
|
| |
(1)
| Excludes the Araku-1 exploration well, offshore Suriname. |
Eastern Mediterranean (Israeland Cyprus) One of our operating areas is the Eastern Mediterranean, where we have identified the existence of substantial natural gas resources since we obtained our first exploration license offshore Israel in 1998.
Israel, theour only producing country in our Eastern Mediterranean area, contributed an average of 272 MMcf/239 MMcfe/d, net, of natural gas sales volumes in 2017,2018, representing approximately 12% of total consolidated sales volumes, primarily from the Tamar field. With the additionAs of December 31, 2018, we had 830 MMBoe of proved reserves in Israel, which represents approximately 43% of total proved reserves. Reserves include proved undeveloped reserves associated with the Leviathan field development in 2017, Israel represented approximately 47% of total proved reserves at December 31, 2017.development. Our leasehold position in the Eastern Mediterranean at December 31, 2017,2018, included foursix leases and three licensesone license operated offshore Israel. OffshoreIn offshore Cyprus, we operate under the terms of a PSC.
At December 31, 2017,2018, the Eastern Mediterranean position included approximately 78,00074,000 net developed acres and 116,000111,000 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 acres adjacent to our offshore Israel acreage.
Locations of our operations in the Eastern Mediterranean as of December 31, 20172018 are shown below:
Offshore Israel Noble Energy and our partners have delivered reliable and affordable natural gas to Israeli citizenscustomers for over a decade. During this time, we have delivered approximately 2.32.65 Tcf, gross, of natural gas to Israeli customers, including the Israel Electric Corporation (IEC), the largest supplier of electricity in the country.
We are the first company to construct, operate and produce from a major natural gasenergy 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 theTamar field with a discovery to production cycle time of approximately four years, which is exceptionally fast by global industry standards for an offshore natural gas project of this magnitude and complexity.
In 2010, we discovered the Leviathan field, our largest natural gas discovery to date. The quantity of discovered natural gas resources at Tamar and Leviathan positions Israel to meet domestic needs for decades and to become a significant natural gas exporter. Multiple natural gas customers exist in the region, and Israel’s domestic demand is predicted to continue to grow over the next decade, primarily driven by increased use of natural gas over coal to fuel electric power generation. During 2017, growth in power, industrial2018, increased demand for electricity, continued coal displacement and residential demand in Israel and first exports to Jordan, coupled with almost 100% asset uptime, enabled us to set a new Tamar cumulative sales volume record of 956 MMcfe/d, gross, from fields offshore Israel.1.75 Tcf gross. As customer demand increases and to reinforce the reliability of the Tamar project, we have continued to progress regulatory approval with the Government of Israel regarding the development plan for our 2013 Tamar Southwest discovery.
In addition to our natural gas discoveries, the Levant Basin is prospective for crude oil discoveries at greater depths. We conducted preliminary exploration activities in 2012 and, are analyzing thein 2018, continued analysis of potential for 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 International Marketing Activities and Delivery and Firm Transportation Commitments – Israel Agreements, below.. 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 Tamar field online providing reliable production, and the development of the Leviathan field progressing, we are well positioned to supply natural gas to the region for many years. In first quarter 2018, we announced the execution of certain agreements to supply natural gas from the Leviathan and Tamar fields to customers in Egypt. See GSPAs and Transportation Agreements for Israeli Export, below.
Israel Natural Gas Projects
Tamar Natural Gas Project (32.5% (25% operated working interest) The Tamar project began production in March 2013 and has peak flow rates of approximately 1.1 Bcf/d, gross, to support seasonal high demand periods.gross. In 2015, we completed the Tamar compression project, which expanded field production capacity by adding compression at the Ashdod onshore terminal (AOT) and. In 2017, we installed subsea equipment to connect the Tamar 8 development well to the Tamar subsea system. Additionally, in 2017 we completed and commenced production from the Tamar 8 development well. The Tamar 8 well, which increases supply reliability as domestic demand for natural gas continues to grow.
In 2017, we installed subsea equipment to allow for future tie-back ofJanuary 2019, the Petroleum Commissioner approved the development plan associated with our 2013 Tamar Southwest discovery, intowhich includes the Tamar platform and other existing infrastructure. We continuedrilling of an additional development well to work with the Government of Israel to obtain regulatory approval of the development plan, which would help reinforce the reliability for the Tamar project and support increased customer demand.
We are also assessing the possibility for expansion of the Tamar project. The project wouldcould expand field deliverability from the current capacity level of approximately 1.2 Bcf/d to up to approximately 2.1 Bcf/d, a quantity that wouldcould allow for additional regional export. Expansion wouldoptions could include a third flow line componentadditional investments in pipelines, wells and additional producing wells.platform upgrades. Timing of project sanction is dependent upon progress relating to domestic and regional marketing efforts of these resources as well as regulatory approvals from respective governments.governments and capital allocation management.
The Israel Natural Gas Framework (Framework) providesprovided for the reduction in our ownership interest in the Tamar and Dalit fieldsfield from 36% to 25% by year-end 2021. In 2016,We completed the sell-down through a series of transactions, whereby we divested 3.5% of our interest in these respective fields, partially fulfilling this commitment required by the Framework. Further, on January 29,2016, and in March 2018, we signed a definitive agreement to divestclosed the sale of a 7.5% working interest in these respective fieldsTamar 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. 4.Note 5. Acquisitions Divestitures and MergerDivestitures.
Leviathan Natural Gas Project (39.66% operated working interest) In early 2017, we announced project 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 toremaining costs will be funded from our share of cash flows from the Tamar asset and expected proceeds to be received from the sell-down of our ownership interest in Tamar as noted above. In addition, we have the ability to borrow under the Leviathan Term Loan Facility (defined below).asset. As we progress through the firstinitial phase of development, we have included volume capacity expansion optionality on the Leviathan platform to allow for cost effective expansion to meet growing regional natural gas demand.
During 2017, we commenced drilling and continued detailed design and engineering activities and fabricationAs of onshore facilities, topsides, jacket and subsea equipment. We will continue drilling activities and commence well completions inDecember 31, 2018, as we progress the project towards first gas salesis 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. As of December 31, 2017, the project remained within budget and on schedule at approximately 35% complete, with all critical path equipment and major contracts secured.
The marketing and development of natural gas from this asset is intended to serve both domestic demand and regional export. We are actively engaged in natural gas marketing activities to fill Leviathan Phase 1 capacity and have progressed multiple GSPAs totalingwith initial contracted quantities during 2020-2022 of up to approximately 525922 MMcf/d, gross (approximately 208320 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.
Our largest Leviathan GSPA, withfield 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. We continue to market
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 toward realizing full utilizationare anticipated to begin at a firm rate of approximately 350 MMcf/d, gross (approximately 121 MMcf/d, net), at the startup of the 1.2 Bcf/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 productionconditions 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. See Israel Natural Gas FrameworkClosing of the agreement is subject to fulfillment of certain conditions precedent, which is expected in the first half of 2019, and Regulatory Environment, below.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. WeAs of December 31, 2018, we are performing geologic and environmental studies necessary to progressin the prospect to an investment decision.process of relinquishing the license.
Other Discoveries Offshore IsraelDalit Discovery Our development plan for the Dalit field (32.5%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.
Asset Impairments No impairment expense was recorded during 2017. During 2016, we recorded impairment expense of $88 million related to certain Leviathan field development concepts which were not selected. During 2015, we recorded impairment expense of $36 million, primarily due to an increase in field abandonment costs. See Item 8. Financial Statements and Supplementary Data – Note 5. Asset Impairments.Israel Natural Gas Framework and Regulatory 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.
Cyprus Natural Gas Project (Offshore Cyprus)During fourth quarter 2015, we entered into a farm-out agreement with a partner for a 35% interest in Block 12, which includes the Aphrodite natural gas discovery, for $171 million. We received initial proceeds of $131 million related to the farm-out agreement in 2016 and received the remaining consideration, subject to post-close adjustments, in January 2017. We continue to operate with a 35% interest. As part of the farm-out process, we negotiated a waiver of our remaining exploration well obligation.
In September 2017, we submitted an updated development plan to the Government of Cyprus. We continue to work with the Government of Cyprus to obtain approvalon a plan of the development plan and the issuance of an Exploitation License for the Aphrodite field. Receiving an Exploitation License, in conjunction with securing markets for Aphrodite natural gas, will allow us and our partners to perform the necessary FEED studies and progress the project to final investment decision. In preparation for FEED, we and our partners are currently performing preliminary engineering and design (pre-FEED) for the potential development of the Aphrodite field that, as currently planned, would deliver natural gas to regional customers. During 2017,In addition, we progressed
are focused on capital project cost improvements, and continued regionalas well as natural gas marketing efforts.efforts and execution of natural gas sales and purchase agreements, which, once secured, will progress the project to a final investment decision.
West Africa (Equatorial Guinea, Cameroon and Gabon) West Africa is one of our operating areas and includes the Alba field, Block O and Block I offshore Equatorial Guinea, the YoYo PSC, offshore Cameroon, and one block offshore Gabon. In West Africa, our interests can be burdened by overriding royalty interests and/or other government interests. As such, our working interests may differ from our revenue interests. Equatorial Guinea is currently ourthe only producing country in our West Africa segment and, excluding the impact of equity investees, Equatorial Guinea contributed an average of 5751 MBoe/d of sales volumes in 20172018 and represented approximately 15% of total consolidated sales volumes. At December 31, 2017,2018, Equatorial Guinea representedhad proved reserves of 97 MMBoe, which represents approximately 5% of total proved reserves. We held approximately 118,000 net developed acres and 30,000 net undeveloped acresNo wells were completed or participated in Equatorial Guinea, 168,000 net undeveloped acres in Cameroon, and 403,000 net undeveloped acres in Gabon at December 31, 2017.during the year.
Locations of our upstream operations in Equatorial Guinea and Cameroon,West Africa, as of December 31, 20172018 are shown on the map below:
Aseng Field Aseng is an oil field on Block I (40% operated working interest, 38% revenue interest), offshore Equatorial Guinea, which began producing in 2011. The development includes five horizontal producing wells flowing to the Aseng floating production, storage and offloading vessel (FPSO) where the crude oil is stored until sold, and natural gas and water are reinjected into the reservoir to maintain pressure and maximize crude oil recoveries. During 2017,2018, sales volumes from the Aseng field produced approximately 7 MBoe/averaged 6 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 over 99%almost 100% production uptime and, as of December 31, 2017,2018, has produced 89over 95 MMBbls of cumulative gross crude oil production.
In late 2018, 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 infrastructure and is expected to add crude oil reserves, minimize field declines and extend the reservoir life of the Aseng field. We expect to sanction the project in the near future with first oil anticipated in late 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, which includes three production wells and three natural gas injection wells connected to a production platform that utilizesplatform. Condensate is pumped to the Aseng FPSO for storage and offloading. Alen has been producing since 2013 and producedsales volumes averaged approximately 4 MBoe/2 MBbl/d, net, during 2017.2018. As of December 31, 2017,2018, Alen has produced over 3336 MMBbls of cumulative gross condensate production.
The Alen platform is expected to be utilized in our natural gas monetization efforts. See West Africa Natural Gas Monetization, below.
In October 2017, we executed a unitization agreement on the Alen field with our partners and the Government of Equatorial Guinea. The agreement was between Block O and Block I interest owners. We expect the impact on our allocated future sales volumes to be de minimis.
Alba FieldAlba is a natural gas and condensate field located offshore Equatorial Guinea (33% non-operated working interest, 32% revenue interest), which has been producing since 1991. Operations include the Alba field and related production and condensate storage facilities, a liquefied petroleum gas (LPG)LPG processing plant where additional condensate is extracted along with LPGs, and a methanol plant capable of producing up to 3,100 gross metric tons per day of methanol. The LPG processing plant and the methanol plant are located on Bioko Island, Equatorial Guinea. During 2017,2018, Alba field sales volumes totaled 54averaged 50 MBoe/d, net, reflecting 4643 MBoe/d attributable to total sales volumes and 87 MBoe/d attributable to an equity investee.
In April 2017, we executed a unitization agreement on the Alba field with our partner and the Government
We sell our share of primary condensate produced in the Alba field under short-term contracts at market-based prices. We sell our share of natural gas production from the Alba field to the LPG plant, the methanol plant, and an unaffiliated liquefied natural gas (LNG) plant and a power generation plant. The LPG plant is owned by Alba Plant LLC (Alba Plant), in which we have a 28% interest. The methanol plant is owned by Atlantic Methanol Production Company, LLC (AMPCO), in which we have a 45% interest. AMPCO purchases natural gas from the Alba field under a contract that runs through 2026 and subsequently markets the produced methanol primarily to customers in the US and Europe. Alba Plant sells its LPG products and secondary condensate at our marine terminal at prevailing market prices.
West Africa Natural Gas MonetizationWe continue our efforts to monetize theour significant natural gas resources represented by our discoveries offshore West Africa including our 2007(YoYo, Yolanda discovery (Block I), the YoYo discovery, offshore Cameroon, as well as natural gas from our Aseng and Alen fields.Felicita).
As part of our monetization efforts, aA natural gas development team has been working with local governments to evaluate natural gas monetization concepts. After analyzing existing infrastructure, includingdevelopment plans and progress negotiations of required contracts. In May 2018, we announced the execution, along with the Government of the Republic of Equatorial Guinea and necessary third-parties, of a Heads of Agreement establishing the framework for development of natural gas from the Alen field. The agreement outlines the high-level commercial terms for Alen natural gas to be processed through Alba Plant and Equatorial Guinea LNG Holdings Limited’s LNG plant. Both plants are located in Punta Europa. The contemplated structure would result in Alen natural gas being marketed to global LNG customers. Sanction of the project is contingent upon final commercial agreements being executed.
Existing production and processing facilities in place at the Alen platform and other facilities, we believe these assets can be efficiently modifiedin Punta Europa require certain modifications to produce and retrofitted to allow for future commercialization ofprocess the Alen natural gas. Leveraging existing assets for the developmentThe agreement contemplates construction of a 65-kilometer pipeline to transport natural gas minimizes future capital expenditures while providing advantageous financial returns.from the Alen platform to 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 approximately 168,000 undeveloped acres offshore Cameroon in ourthe YoYo PSC (100% operated working interest). The YoYo-1 exploratory well was drilled in 2007, discovering natural gas and condensate. We are working with the government of Cameroon to evaluate natural gas development options, which will provide a more robust framework directly related to oil and gas operational activities. In June 2017, we converted our mining concession license for the YoYo block into a PSC.
Offshore GabonWe are the operator of Block Doukou Dak (60% working interest), an undeveloped, deepwater area, covering approximately 671,000 gross acres.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 the seismic data results.
Other International
Other international operations include the following:
Offshore Newfoundland (Canada) In November 2016, we acquiredWe have a non-operated 25% working interest in exploration parcels (blocks) 3, 4licenses (EL) EL1145, EL 1146 and 8,EL 1148, and a non-operated 40% working interest in exploration parcel (block) 10.EL 1149. BP Canada Energy Group ULC is the operator of the blocks. We have acquiredlicensed 3D seismic data which will allowto help us to assess the economic viability of thisnumerous exploration prospect.leads and prospects.
Offshore Suriname We hold a non-operated 20% working interest in Block 54 offshore Suriname in the Atlantic Ocean. In October 2017, our partner spud the Araku-1explorationAraku-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 and are currently analyzing thein 2017. Based upon well results, to update modeling of the basin and review of further prospectivity. See Note5. Asset Impairments.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 containscontained the Rhea prospect. The exit resulted in aprospect, 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, 2017, there is2018, we no remaining net book value associated with the assets.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. For example, during 2017, the operator of the MacCulloch field notified working interest owners that the scope and magnitude of decommissioning activities has been revised downward, resulting in lower projected field abandonment costs. As such, we recorded a revision of $42 million in 2017 that decreased our estimated asset retirement obligation for the remediation project. The discounted obligation totaled 44 million at December 31, 2017. We will continue to monitor the status and costs of the project and will adjust our estimate accordingly.
Midstream – Properties and Activities
We continue to develop our Midstream business,segment, which includes gathering, treating, and transportation assets, as well as water-related infrastructure, including fresh water delivery and produced water disposal assets, that support our upstream operations.assets. Our Midstream assets are strategically located with our explorationdevelopment and production activities in the DJ and Delaware Basins. These assets alsoBasins and provide services to third partyus and other third-party customers.
Noble Midstream Partners Our Midstream operations include those of Noble Midstream Partners, a publicly traded, consolidated subsidiary and limited partnership that owns,constructs and operates develops, and acquires a wide range of domestic midstream infrastructure
assets. Noble Midstream Partners is a fee-based, growth-oriented Delaware master limited partnership formed in December 2014 organized in a development company structure. At December 31, 2017, our ownership interest in Noble Midstream Partners consisted of a 45.5% limited partner interest, the entire non-economic general partner interest, and all of the incentive distribution rights. On September 20, 2016, Noble Midstream Partners completed its initial public offering of common units, which provided Noble Midstream Partners access to the capital markets to support funding of ourits US onshore midstream investment program. At December 31, 2018, our ownership interest in Noble Midstream Partners consisted of a 45.4% limited partner interest, the entire non-economic general partner interest, and all incentive distribution rights.
In addition to developing and operating midstream assets, Noble Midstream Partners leveraged its existing dedications and commercial relationships through investing in certain partnerships providing transportation services downstream of our current operations. As of December 31, 2018, Noble Midstream Partners has a 50% interest in Advantage Pipeline L.L.C. (Advantage Pipeline) in the Delaware Basin and a 3.33% interest in White Cliffs Pipeline L.L.C. (White Cliffs) in the DJ Basin. In first quarter 2019, we assigned Noble Midstream Partners our option 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. See Item 8. Financial Statements and Supplementary Data – Note 5. Acquisitions and Divestitures. The following diagram depicts our organizational structure as of December 31, 2017.2018. Development companies identified in red and blue indicate the location of the assets as either in the DJ Basin or Delaware Basin, respectively.
Advantage Joint Venture In April 2017, Noble Midstream Partners, along with its partner, Plains Pipeline, L.P., formed the Advantage joint venture (Advantage Joint Venture) and subsequently completed the acquisition of Advantage Pipeline L.L.C. (Advantage Pipeline). Noble Midstream Partners serves as the operator of the Advantage Pipeline System, which includes a 70-mile crude oil pipeline (Advantage Delaware Basin Pipeline) in the Delaware Basin from Reeves County, Texas to Crane County, Texas with 150 MBbls per day of capacity (expandable to over 200 MBbls per day) and 490 MBbls of storage capacity. Noble Midstream Partners owns a 50% interest in the joint venture.
Asset Contribution On June 26, 2017, Noble Midstream Partners acquired an additional 15% limited partner interest in Blanco River DevCo LP (Blanco River DevCo), increasing its ownership to 40% of Blanco River DevCo, and acquired the remaining 20% limited partner interest in Colorado River DevCo LP (Colorado River DevCo) from Noble Energy. Blanco River DevCo holds Noble Midstream Partners’ Delaware Basin in-field gathering dedications for crude oil and produced water gathering services on approximately 111,000 net acres, with substantially all of the acreage also dedicated for natural gas gathering. Colorado River DevCo consists of gathering systems across Noble Energy’s Wells Ranch and East Pony development areas in the DJ Basin.
Black Diamond Gathering and Acquisition of Saddle Butte Pipeline In December 2017, Noble Midstream Partners and Greenfield Midstream, LLC (Greenfield Midstream) formed an entity, Black Diamond Gathering LLC (Black Diamond Gathering), to acquire Saddle Butte Rockies Midstream, LLC and affiliates (Saddle Butte). The acquisition includes a large-scale integrated crude oil gathering system in the DJ Basin, consisting of approximately 160 miles of pipeline in operation and 300 MBbls per day of delivery capacity. Saddle Butte has approximately 141,000, net dedicated acres from six customers under fixed fee arrangements.
The transaction closed on January 31, 2018, with Noble Midstream Partners funding $319.9 million of the total cash consideration of $638.5 million. Noble Midstream Partners received a 54.4% equity ownership and Greenfield Midstream will own the remaining 45.6% of Black Diamond Gathering. Noble Midstream Partners will operate the Saddle Butte system.
Marcellus Shale CONE Gathering Divestiture In late 2017, we announced the signing of a definitive agreement to divest our 50% interest in CONE Gathering, LLC (CONE Gathering). CONE Gathering owns the general partner of CONE Midstream Partners LP (CONE Midstream). As of December 31, 2017, the net book value of the assets held by Noble Energy
was approximately $181 million. In January 2018, we closed the sale of CONE Gathering, receiving cash proceeds of $308 million. We now hold 21.7 million common units representing limited partner interests in CNX Midstream Partners LP (NYSE: CNXM). As of December 31, 2017, the net book value of the limited partner interests was approximately $70 million.
Major Construction Projects Our activityActivity in 20172018 primarily focused on construction and development of midstream infrastructure assets, including:
completioncompleted 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 produced water expansion project servicing the Wells Ranch IDP area;
completion of crude oil and produced water gathering systems servicing the Greeley Crescent IDP area;
completion of the connection from the CGFpipeline system in the Delaware Basin, to the Advantage Pipeline,for which began allowing crude oil to flow from the completed facility to the Advantage Pipelinedefinitive agreements with Salt Creek were executed in third quarter 2017;
completion of the construction of two CGFs in the Delaware Basin; and
continued construction activities on expansion of our freshwater system servicing the Mustang IDP area and the commencement of construction of the backbone gathering infrastructure build-out, which is expected to be completed in early 2018.February 2019.
In 2018,2019, we expect to continue our midstream investment to continue to focus on the DJ and Delaware Basins to meet the needs of our upstream operations.operations and third-party customers.
Third Party SalesNoble 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 2017, we began2018, Noble Midstream Partners continued providing crude oil and produced water gathering and fresh water delivery services to an unaffiliated third partyparties 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.
Proved Reserves DisclosuresDelivery Commitments
Internal Controls Over Reserves EstimatesOur policies and processes regarding internal controls over the recording of reserves estimates require reserves to be in compliance with the Securities and Exchange Commission (SEC) definitions and guidance and prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our internal controls over reserves estimates also include the following:
the Audit Committee of our Board of Directors reviews significant reserves changes on an annual basis;
fields that meet a minimum reserve quantity threshold, newly sanctioned development projects, and certain fields selected on a rotational basis, which combined represent over 80% of our proved reserves, are audited by Netherland, Sewell & Associates, Inc. (NSAI), a third-party petroleum consulting firm, on an annual basis; and
NSAI is engaged by, and has direct access to, the Audit Committee. See Third-Party Reserves Audit, below.
Responsibility for compliance in reserves estimation is delegated to our Corporate Reservoir Engineering group. Qualified petroleum engineers in our Houston and Denver offices prepare all reserves estimates for our different geographical regions. These reserves estimates are reviewed and approved by regional management and senior engineering staff with final approval by the Senior Vice President – Corporate Development and certain other members of senior management.
Our Senior Vice President – Corporate Development oversees our corporate business development, strategic planning, and reserves departments. He is the technical person primarily responsible for overseeing the preparation of our reserves estimates and the third-party audit of our reserves estimates. He has Bachelor of Science and Master of Science degrees in Petroleum Engineering and over 37 years of industry experience with positions of increasing responsibility in engineering, evaluations, and business unit management at the Company. The Senior Vice President – Corporate Development reports directly to our Chief Executive Officer.
Technologies Used in Reserves EstimationThe SEC’s reserves rules allow the use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
We used a combination of production and pressure performance, wireline wellbore measurements, simulation studies, offset analogies, seismic data and interpretation, wireline formation tests, geophysical logs and core data to calculate our reserves estimates, including the material additions to the 2017 reserves estimates.
Based on reasonable certainty of reservoir continuity in US onshore formations where we operate, we may record proved reserves associated with wells more than one offset location away from an existing proved producing well. All of our wells drilled that were more than one offset away from a proved producing well at the time of drilling were determined to be economically producible.
Third-Party Reserves Audit In each of the years 2017, 2016, and 2015, we retained NSAI to perform audits of proved reserves. The reserves audit for 2017 included a detailed review of six of our major US onshore and international fields, which covered approximately 92% of US proved reserves and 99% of international proved reserves (95% of total proved reserves). The reserves audit for 2016 included a detailed review of nine of our major US onshore and international fields, which covered approximately 88% of US proved reserves and 99.9% of international proved reserves (92% of total proved reserves). The reserves audit for 2015 included a detailed review of nine of our major fields and covered approximately 91% of total proved reserves.
In connection with the 2017 reserves audit, NSAI prepared its own estimates of our proved reserves. In order to prepare its estimates of proved reserves, NSAI examined our estimates with respect to reserves quantities, future production rates, future net revenue, and the present value of such future net revenue. NSAI also examined our estimates with respect to reserves categorization, using the definitions for proved reserves set forth in Rule 4-10(a) of Regulation S-X and subsequent SEC staff interpretations and guidance.
In the conduct of the reserves audit, NSAI did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, crudeOnshore AgreementsCrude oil, and natural gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the fields and sales of production. However, if in the course of the examination something came to the attention of NSAI which brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data.
NSAI determined that our estimates of reserves have been prepared in accordance with the definitions and regulations of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years, under existing economic and operating conditions, consistent with the definition in Rule 4-10(a)(24) of Regulation S-X. NSAI issued an unqualified audit opinion on our proved reserves at December 31, 2017, based upon their evaluation. NSAI concluded that our estimates of proved reserves were, in the aggregate, reasonable and have been prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. NSAI’s report is attached as Exhibit 99.1 to this Annual Report on Form 10-K.
When compared on a field-by-field basis, some of our estimates are greater and some are less than the estimates of NSAI. Given the inherent uncertainties and judgments that go into estimating proved reserves, differences between internal and external estimates are to be expected. For proved reserves at December 31, 2017, on a quantity basis, the NSAI field estimates ranged from 18 MMBoe or 8% below to 9 MMBoe or 2% above as compared with our estimates on a field-by-field basis. Differences between our estimates and those of NSAI are reviewed for accuracy but are not further analyzed unless the aggregate variance is greater than 10%. Reserves differences at December 31, 2017 were, in the aggregate, approximately 17 MMBoe, or less than 1%.
Proved Reserves
We have historically added reserves through our exploration program, development activities, and acquisition of producing properties. Changes in proved reserves were as follows: |
| | | | | | | | | |
| | | Year Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| (MMBoe) | | | | | | |
| Proved Reserves Beginning of Year | | 1,437 |
| | 1,421 |
| | 1,404 |
|
| Revisions of Previous Estimates | | 135 |
| | 64 |
| | (216 | ) |
| Extensions, Discoveries and Other Additions | | 736 |
| | 179 |
| | 100 |
|
| Purchase of Minerals in Place | | 57 |
| | 4 |
| | 269 |
|
| Sale of Minerals in Place | | (261 | ) | | (77 | ) | | (6 | ) |
| Production | | (139 | ) | | (154 | ) | | (130 | ) |
| Proved Reserves End of Year | | 1,965 |
| | 1,437 |
| | 1,421 |
|
RevisionsRevisions of previous estimates represent changes in previous reserves estimates, either upward (positive) or downward (negative), resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs, development costs or abandonment costs. Revisions primarily included the following:
positive price revisions of 30 MMBoe globally, as well as positive performance revisions of 49 MMBoe for the Tamar field, offshore Israel, 30 MMBoe for the Delaware Basin and 22 MMBoe for the Eagle Ford Shale, partially offset by abandonment cost increases for US onshore in 2017;
positive revisions of 43 MMBoe for the DJ Basin, 42 MMBoe for the Marcellus Shale, 11 MMBoe for the Delaware Basin, and 10 MMBoe for the Alba field, offshore Equatorial Guinea, due to increased performance and/or lower development or operating costs; partially offset by negative revisions of 53 MMBoe due to lower commodity prices in 2016; and
negative price revisions of 307 MMBoe, partially offset by positive performance revisions of 81 MMBoe for the Marcellus Shale and 17 MMBoe for the Delaware Basin in 2015.
Extensions, Discoveries and Other AdditionsThese are additions to proved reserves that result from (1) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (2) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields. Extensions, discoveries and other additions primarily included the following:
increases primarily relate to 99 MMBoe in the DJ Basin and 77 MMBoe in the Delaware Basin as a result of enhanced completion techniques in our horizontal drilling programs and an increase of 551 MMBoe due to the sanction of the first phase of development at the Leviathan natural gas field in 2017;
increases of 83 MMBoe in the DJ Basin, 42 MMBoe in the Marcellus Shale, 33 MMBoe in the Delaware Basin and 21 MMBoe in the Eagle Ford Shale, all associated with our horizontal drilling programs in 2016; and
increases of 86 MMBoe in the DJ Basin and 14 MMBoe in the Marcellus Shale associated with our horizontal drilling programs in 2015.
Purchase of Minerals in PlaceWe occasionally enhance our asset portfolio with strategic acquisitions of producing properties. Purchases primarily included the following:
an increase of 57 MMBoe in the Delaware Basin primarily as a result of the Clayton Williams Energy Acquisition in 2017; and
the acquisition of additional acreage, primarily in the Eagle Ford Shale and Delaware Basin in Texas in 2015 in connection with the Rosetta Merger.
Sale of Minerals in Place We maintain an ongoing portfolio management program through which we may periodically divest assets. Sales primarily included the following:
a reduction of 241 MMBoe related to the Marcellus Shale upstream divestiture, as well as 20 MMBoe associated with divestment of non-strategic US onshore assets in 2017;
a reduction of 36 MMBoe in Israel driven by our 3.5% sale of Tamar working interest, as well as a 29 MMBoe divestment in the Marcellus Shale in 2016; and
the sale of non-strategic US onshore assets in 2015.
Proved Undeveloped Reserves (PUDs) As of December 31, 2017, our PUDs totaled 249 MMBbls of crude oil and condensate, 4.5 Tcf ofNGLs, natural gas and 99 MMBbls of NGLs for a total of 1,097 MMBoe, or 56% of proved reserves. Changes in PUDs that occurred during the year are summarized below: |
| | | | | | | | | |
| | | United States | | Israel | | Total |
| (MMBoe) | | | | | | |
| Proved Undeveloped Reserves Beginning of Year | | 422 |
| | 64 |
| | 486 |
|
| Revisions of Previous Estimates | | 26 |
| | — |
| | 26 |
|
| Extensions, Discoveries and Other Additions | | 174 |
| | 551 |
| | 725 |
|
| Purchase of Minerals in Place | | 36 |
| | — |
| | 36 |
|
| Sale of Minerals in Place | | (54 | ) | | — |
| | (54 | ) |
| Conversion to Proved Developed | | (122 | ) | | — |
| | (122 | ) |
| Proved Undeveloped Reserves End of Year | | 482 |
| | 615 |
| | 1,097 |
|
Revisions of previous estimates include the transfer of PUDs to unproved reserve categories as a result of changes in development plans and/or the impact of changes in commodity prices, and the addition of new PUDs arising from current development plans. Positive revisions of 26 MMBoe in the US for 2017 included 7 MMBoe related to positive price revisions and 19 MMBoe related to enhancements of our horizontal drilling programs.
Extensions, discoveries and other additions include the addition of proved reserves through additional drilling or the discovery of new reservoirs in proven fields. During 2017, we recorded the following additions as a result of successful expansion of our long lateral well programs in US onshore and recording of reserves for Leviathan:
94 MMBoe in the DJ Basin;
74 MMBoe in the Delaware Basin;
6 MMBoe in the Eagle Ford Shale; and
551 MMBoe in the Leviathan field.
Conversion to proved developed reserves included the following transfers:
34 MMBoe in the DJ Basin;
17 MMBoe in the Delaware Basin;
60 MMBoe in the Eagle Ford Shale; and
11 MMBoe in the Marcellus Shale, prior to divestiture.
US PUDs Locations In 2017, we converted 122 MMBoe of our US PUDs, or 29% of our US PUDs beginning balance, to developed status. Based on our current inventory of identified horizontal well locations and our anticipated rate of drilling and completion activity, we expect our US PUDs recorded as of December 31, 2017 to be converted to proved developed reserves within five years of initial disclosure.
As of December 31, 2017, our US PUDs included:
263 MMBoe in the DJ Basin;
181 MMBoe in the Delaware Basin; and
38 MMBoe in the Eagle Ford Shale.
Our PUDs are expected to be recovered from new wells on undrilled acreage or from existing wells where additional capital expenditures are required for completion, such as drilled but uncompleted (DUC) wells. As of December 31, 2017, we had approximately 32 MMBoe of PUDs associated with DUC well locations related to our US onshore operations, approximately 75% of which are in the DJ Basin and the remainder are in the Delaware Basin and Eagle Ford Shale.
International PUDs LocationsAs of December 31, 2017, our international PUDs included 615 MMBoe in Israel, of which 551 MMBoe relate to the Leviathan field, which is currently in the first phase of development. The Tamar field contains 35 MMBoe, and the Tamar Southwest field, which is awaiting government approval of the development plan, contains 29 MMBoe. Our Tamar Southwest PUDs of 29 MMBoe, or less than 5% of our international PUDs, are expected to remain undeveloped for five years or longer since initial disclosure in 2013. We have been working with the government of Israel for the approval of the development plan and have continued capital investment within this field, including laying subsea equipment in 2017 for future tie-in of field production into existing Tamar infrastructure. Other than the Tamar Southwest PUDs, we expect all of our international PUDs, including those associated with the initial phase of development at the Leviathan field, to be converted to proved developed reserves within five years of initial disclosure.
Development CostsCosts incurredto convert PUDs to proved developed reserves were approximately $1.2 billion in 2017, $656 million in 2016, and $1.5 billion in 2015. Costs incurred in 2017 primarily related to the DJ Basin, Delaware Basin and Eagle Ford Shale development projects, as well as certain costs incurred for the development of the Tamar 8 well. In addition, we incurred approximately $416 million in 2017 to advance the development of the Leviathan PUDs which are expected to be converted to proved developed reserves in 2019.
Estimated future development costs relating to the development of all PUDs are projected to be approximately $1.7 billion in 2018, $1.9 billion in 2019, and $1.4 billion in 2020. Estimated future development costs include capital spending on development projects and PUDs related to development projects will be reclassified to proved developed reserves when production commences.
Drilling Plans Our long range development plans will result in the conversion of all PUDs to developed reserves within five years of their initial disclosure, with the exception of the previously mentioned Tamar Southwest PUDs. PUDs associated with the Tamar Southwest field are expected to be converted to proved developed reserves prior to the end of 2020 as contemplated in our long range development plans, subject to local government approval. Initial production from all PUDs is expected to begin during the years 2018 to 2022.
In accordance with US GAAP, we disclose a standardized measure of discounted future net cash flows related to our proved reserves. In order to standardize the measure, all companies are required to use a 10% discount rate and SEC pricing rules. This prescribed calculation can result in some PUDs having negative present worth, meaning while these PUDs have positive cash flows, the rate of return is lower than 10%. As of December 31, 2017, we had no PUDs with a negative present worth when discounted at 10%.
For more information see the following:
Sales Volumes, Price and Cost DataSales volumes, price and cost data are as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Sales Volumes | | Average Sales Price | | Production Cost (1) |
| | | Crude Oil & Condensate MBbl | | NGLs MBbl | | Natural Gas
MMcf | | Crude Oil & Condensate Per Bbl | | NGLs Per Bbl | | Natural Gas
Per Mcf | | Per BOE |
Year Ended December 31, 2017 (2) | | | | | | | | | | | | |
| United States | | | | |
| | | | | | | | | | |
| 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 |
| | N/M |
|
| Total Israel | | 130 |
| | — |
| | 99,240 |
| | 46.95 |
| | — |
| | 5.32 |
| | 2.01 |
|
Equatorial Guinea (3) | | 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 (4) | | 662 |
| | 2,162 |
| | — |
| | 55.13 |
| | 38.48 |
| | — |
| | N/M |
|
| Total | | 47,806 |
| | 23,248 |
| | 407,976 |
| | $ | 49.84 |
| | $ | 24.81 |
| | $ | 3.01 |
| | N/M |
|
Year Ended December 31, 2016 (2) | | | | | | | | | | | | |
| United States | | | | |
| | | | | | | | | | |
| 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 |
| | N/M |
|
| Total Israel | | 140 |
| | — |
| | 102,808 |
| | 36.67 |
| | — |
| | 5.21 |
| | 2.60 |
|
Equatorial Guinea (3) | | 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 (4) | | 629 |
| | 1,993 |
| | — |
| | 45.44 |
| | 26.30 |
| | — |
| | N/M |
|
| Total | | 46,529 |
| | 21,825 |
| | 511,115 |
| | $ | 40.46 |
| | $ | 15.96 |
| | $ | 2.42 |
| | N/M |
|
Year Ended December 31, 2015 (2) | | |
| | | | |
| | |
| | | | |
|
| United States | | |
| | |
| | | | |
| | |
| | | | |
|
| DJ Basin | | 20,909 |
| | 6,910 |
| | 85,369 |
| | $ | 44.37 |
| | $ | 14.21 |
| | $ | 2.53 |
| | $ | 5.75 |
|
| Marcellus Shale | | 673 |
| | 3,480 |
| | 143,465 |
| | 22.39 |
| | 14.04 |
| | 1.75 |
| | 1.38 |
|
| Other US | | 7,680 |
| | 3,705 |
| | 29,806 |
| | 42.83 |
| | 13.25 |
| | 2.56 |
| | 7.15 |
|
| Total US | | 29,262 |
| | 14,095 |
| | 258,640 |
| | 43.46 |
| | 13.91 |
| | 2.10 |
| | 4.46 |
|
| Israel | | | | | | | | | | | | | | |
| Tamar Field | | 121 |
| | — |
| | 91,884 |
| | 46.91 |
| | — |
| | 5.34 |
| | 3.12 |
|
| Other Israel | | — |
| | — |
| | 136 |
| | — |
| | — |
| | 3.01 |
| | N/M |
|
| Total Israel | | 121 |
| | — |
| | 92,020 |
| | 46.91 |
| | — |
| | 5.34 |
| | 3.15 |
|
Equatorial Guinea (3) | | 11,416 |
| | — |
| | 82,729 |
| | 48.85 |
| | — |
| | 0.27 |
| | 5.22 |
|
| United Kingdom | | 88 |
| | — |
| | 49 |
| | 55.52 |
| | — |
| | 6.32 |
| | N/M |
|
| Total Consolidated Operations | | 40,887 |
| | 14,095 |
| | 433,438 |
| | 45.00 |
| | 13.91 |
| | 2.44 |
| | $ | 4.54 |
|
Equity Investee (4) | | 554 |
| | 1,850 |
| | — |
| | 48.85 |
| | 28.40 |
| | — |
| | N/M |
|
| Total | | 41,441 |
| | 15,945 |
| | 433,438 |
| | $ | 45.05 |
| | $ | 15.59 |
| | $ | 2.44 |
| | N/M |
|
N/M Amount is not meaningful.
| |
(1)
| Average production cost includes crude oil and natural gas operating costs and workover and repair expense and excludes production and ad valorem taxes and transportation expense. |
| |
(2)
| For each respective year, reserves associated with the Delaware Basin or the Eagle Ford Shale did not comprise 15% or more of total reserves on a BOE basis. |
| |
(3)
| Natural gas from the Alba field is under contract for $0.25 per MMBtu to a methanol plant, an LPG plant, an LNG plant and a power generation plant. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method. |
| |
(4)
| Volumes represent sales of condensate and LPG from the LPG plant in Equatorial Guinea. |
Revenues from sales of crude oil, NGLs and natural gas have accounted for 90% or more of consolidated revenues for each of the last three fiscal years.
At December 31, 2017, our operated properties accounted for substantially all of our total production. Being the operator of a property improves our ability to directly influence production levels and the timing of projects, while also enhancing our control over operating expenses and capital expenditures.
Productive WellsThe number of productive crude oil and natural gas wells in which we held an interest at December 31, 2017 was as follows: |
| | | | | | | | | | | | | | | | | | |
| | | Crude Oil Wells | | Natural Gas Wells | | Total |
| | | Gross | | Net | | Gross | | Net | | Gross | | Net |
| United States | | 3,565 |
| | 2,682 |
| | 4,918 |
| | 4,382 |
| | 8,483 |
| | 7,064 |
|
| Israel | | — |
| | — |
| | 7 |
| | 2 |
| | 7 |
| | 2 |
|
| Equatorial Guinea | | 5 |
| | 2 |
| | 23 |
| | 8 |
| | 28 |
| | 10 |
|
| Total | | 3,570 |
| | 2,684 |
| | 4,948 |
| | 4,392 |
| | 8,518 |
| | 7,076 |
|
Productive wells are producing wells and wells mechanically capable of production. A gross well is a well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned. The number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof. Wells with multiple completions are counted as one well in the table above.
Developed and Undeveloped AcreageDeveloped and undeveloped acreage (including both leases and concessions) in which we held an interest at December 31, 2017 was as follows:
|
| | | | | | | | | | | | |
| | | Developed Acreage | | Undeveloped Acreage |
| | | Gross | | Net | | Gross | | Net |
| (thousands of acres) | | | | | | | | |
| United States | | | | | | | | |
| Onshore | | 754 |
| | 504 |
| | 564 |
| | 358 |
|
| Gulf of Mexico | | 93 |
| | 52 |
| | 247 |
| | 171 |
|
| Total United States | | 847 |
| | 556 |
| | 811 |
| | 529 |
|
| International | | |
| | |
| | |
| | |
|
| Israel | | 185 |
| | 78 |
| | 284 |
| | 116 |
|
Equatorial Guinea (1) | | 284 |
| | 118 |
| | 81 |
| | 30 |
|
| Suriname | | — |
| | — |
| | 2,095 |
| | 419 |
|
| Newfoundland, Canada | | — |
| | — |
| | 2,331 |
| | 681 |
|
| Gabon | | — |
| | — |
| | 671 |
| | 403 |
|
| Cyprus | | — |
| | — |
| | 95 |
| | 33 |
|
| Cameroon | | — |
| | — |
| | 168 |
| | 168 |
|
| Other International | | 2 |
| | — |
| | 284 |
| | 211 |
|
| Total International | | 471 |
| | 196 |
| | 6,009 |
| | 2,061 |
|
| Total | | 1,318 |
| | 752 |
| | 6,820 |
| | 2,590 |
|
| |
(1)
| Undeveloped acreage includes an exploration lease totaling approximately 55,000 gross (19,000 net) acres which had expired in 2016. The lease was subsequently negotiated with the government of Equatorial Guinea in 2017 and was extended. |
Developed acreage is comprised of leased acres that are within an area spaced by or assignable to a productive well. Undeveloped acreage is comprised of leased acres with defined remaining terms and not within an area spaced by or assignable to a productive well. A gross acre is any leased acre in which a working interest is owned. A net acre is comprised of the total of the owned working interest(s) in a gross acre expressed in a fractional format.
The above table includes certain undeveloped acreage that is set to expire if production is not established or we take no other action to extend the terms of the leases, licenses, or concessions within a specified period of time. Approximately 0.9 million (including 0.4 million in Suriname and 0.4 million in Gabon), 0.3 million, and 0.1 million net acres will expire in 2018, 2019, and 2020, respectively.
Drilling ActivityThe results of crude oil and natural gas wells drilled and completed for each of the last three years were as follows: |
| | | | | | | | | | | | | | | | | | | | | |
| | | Net Exploratory Wells | | Net Development Wells | | |
| | | Productive | | Dry | | Total | | Productive | | Dry | | Total | | Total |
| Year Ended December 31, 2017 | | | | | | | | |
| | | | | | |
| United States | | — |
| | — |
| | — |
| | 185.3 |
| | — |
| | 185.3 |
| | 185.3 |
|
| Israel | | — |
| | — |
| | — |
| | 0.3 |
| | — |
| | 0.3 |
| | 0.3 |
|
| Suriname | | — |
| | 0.2 |
| | 0.2 |
| | — |
| | — |
| | — |
| | 0.2 |
|
| Total | | — |
| | 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 |
|
| Year Ended December 31, 2015 | | | | | | | | |
| | | | | | |
| United States | | 1.5 |
| | 4.0 |
| | 5.5 |
| | 212.5 |
| | — |
| | 212.5 |
| | 218.0 |
|
| Equatorial Guinea | | — |
| | — |
| | — |
| | 0.3 |
| | — |
| | 0.3 |
| | 0.3 |
|
| Cameroon | | — |
| | 0.5 |
| | 0.5 |
| | — |
| | — |
| | — |
| | 0.5 |
|
| Other International | | — |
| | 0.4 |
| | 0.4 |
| | — |
| | — |
| | — |
| | 0.4 |
|
| Total | | 1.5 |
| | 4.9 |
| | 6.4 |
| | 212.8 |
| | — |
| | 212.8 |
| | 219.2 |
|
In addition to the wells drilled and completed in 2017 included in the table above, wells that were in the process of drilling or completing at December 31, 2017 were as follows:
|
| | | | | | | | | | | | | | | | | | |
| | | Exploratory(1) | | Development(2) | | Total |
| | | Gross | | Net | | Gross | | Net | | Gross | | Net |
| United States | | 1 |
| | 0.5 |
| | 114 |
| | 105.0 |
| | 115 |
| | 105.5 |
|
Israel | | 1 |
| | 0.3 |
| | 5 |
| | 2.0 |
| | 6 |
| | 2.3 |
|
| Equatorial Guinea | | 2 |
| | 0.9 |
| | — |
| | — |
| | 2 |
| | 0.9 |
|
| Cameroon | | 1 |
| | 1.0 |
| | — |
| | — |
| | 1 |
| | 1.0 |
|
| Cyprus | | 1 |
| | 0.4 |
| | — |
| | — |
| | 1 |
| | 0.4 |
|
| Total | | 6 |
| | 3.1 |
| | 119 |
| | 107.0 |
| | 125 |
| | 110.1 |
|
| |
(1)
| Includes exploratory wells drilled and suspended awaiting a sanctioned development plan or being evaluated to assess the economic viability of the well. |
| |
(2)
| Includes wells pending completion activities. Israel development wells include the Leviathan 3, 4, 5 and 7 development wells and the Tamar Southwest well. |
Domestic Marketing ActivitiesCrude oil, natural gas, condensate and NGLs produced in the US onshore and Gulf of Mexico are sold under varying contracts, including short-term, and 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. Onshore productionCertain of crude oilour sales and condensate is distributed through pipelines and by trucks and rail carsdelivery agreements may include natural gas processing or NGL fractionation commitments for the volumes delivered, either to gatherers, transportation companies and refineries. Gulf of Mexico production is distributed through pipelines.
With the advent of US onshore shale gas, demand has increased for access to takeaway pipelines for ballooning production volumes. For example, in the Permian Basin, midstream suppliers are working to construct new gathering, transportation and processing facilitiesa customer or to repurpose existing infrastructure in an effort to proactively outpace anticipated production growtha service provider as well as expected future LNG demand from export facilities on the Gulf Coast.
International Marketing ActivitiesOur share of crude oilassessed and condensate from the Aseng and Alen fields is sold at market-based prices to Glencore Energy UK Ltd (Glencore Energy). Our share of crude oil and condensate from the Alba field is sold to Glencore Energy under a short-term sales contract, subject to renewal. These products are transported by tanker.
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.ASC 606.
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, long-term (greater than one year) sales commitments we were contractually committed to deliver included our five-year agreement which brings a portion of our Delaware Basin crude oil to the Texas Gulf Coast. Remaining quantities to be delivered under this agreement are 36.5 MMBbls. We expect to fulfill this delivery commitment with existing proved developed and proved undeveloped reserves, which we regularly monitor to ensure sufficient availability to meet the commitments.
Israel weAgreementsWe currently sell natural gas from the Tamar field and have agreements with multiple customers to sell natural gas under long-term contracts, with initial terms ranging from 15 to 17 years. See Delivery and Firm Transportation Commitments, below.
Delivery and Firm Transportation Commitments
Domestic ContractsWe have entered into various long-term gathering, processing and transportation contracts for some of our US onshore production, with remaining terms of one to 11 years. We use long-term contracts such as these to provide production flow assurance and ensure access to markets for our products at the best possible price and at the lowest possible logistics cost.
Certain of these contracts require us to make payments for any shortfalls in delivering or transporting minimum volumes under the commitments. As properties are undergoing development activities, we may experience temporary shortfalls until production volumes increase to meet or exceed the minimum volume commitments.
For 2017, 2016, and 2015, we incurred expense of approximately $47 million, $58 million, and $33 million, respectively, related to volume deficiencies and/or unutilized commitments primarily in our US onshore operations. These amounts are recorded as marketing expense in our consolidated statements of operations.
We expect to continue to incur expense related to deficiency and/or unutilized commitments in the near-term. Should commodity prices decline or if we are unable to continue to develop our properties as planned, or certain wells become uneconomic and are shut-in, we could incur additional shortfalls in delivering or transporting the minimum volumes and we could be required to make payments in the event that these commitments are not otherwise offset. We continually seek to optimize under-utilized assets through capacity release and third-party arrangements, as well as, for example, through the shifting of transportation of production from rail cars to pipelines when we receive a higher netback price. We may continue to experience these shortfalls both in the near and long-term.
Israel Natural Gas Sales and Purchase AgreementsWe currently sell natural gas from our Tamar field, offshore Israel, to the IEC and numerous other Israeli purchasers, including independent power producers, cogeneration facilities and industrial companies. Most contracts provide for the sale of natural gas over an initial term of 15one to 1718 years. Some of the contracts provide for an increase or reduction in total quantities, and some contracts are interruptible during certain contract periods. Sales prices may be based on an initial base price subject to price indexation over the life of the contract and have a contractual floor. The IEC contract provides for price reopenersrenegotiation in certain years with limits on the increase/decrease from the contractual price.
Under the contracts, we and our partners have a financial exposure in the event we cannot fully deliver the contract quantities. This exposure is capped by contract and will be reflected as a reduction in sales price to the purchaser for periods in which we are delivering partial contract quantities, or as a direct payment to the customer under certain circumstances and with a cap. The cap is subject to force majeure considerations. We believe that any such sales price adjustments or direct payments would not have a material impact on our earnings or cash flows.
As of December 31, 2017,2018, a total of approximately 5.4approximately 4.5 Tcf, gross (1.7(1.0 Tcf, net), of natural gas remained to be delivered under our Tamar contracts. As of December 31, 2017,2018, we have recorded 2.0recorded 1.5 Tcf, net, of proved natural gas reserves, including proved developed reserves of 1.81.3 Tcf, net, and PUD reserves of 212241 Bcf, net, for the Tamar field. Based on current production levels and future development plans, our available quantities of proved reserves are more than sufficient to meet near-term delivery commitments associated with Tamar sale agreementssales 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 gas 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 also actively engaged in domestic and regional marketing activities for future salesanticipated to begin at the startup of the natural gasLeviathan project, currently projected for the end of 2019. As of December 31, 2018, we have recorded 3.3 Tcf, net, of PUD reserves recorded for the Leviathan field. related to sales to Israeli and Jordanian customers. See Eastern Mediterranean (Israel and Cyprus), above. - GSPAs and Transportation Agreements for Israeli Export. West Africa AgreementsOur 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 are 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.
Significant Purchasers
BP North American Funding (BP)and Shell Trading (US) (Shell) were the largest single purchasers of our 20172018 production. Sales to BP accounted for 10% of 2017 total crude oil, natural gas and NGL sales, or 15% of 2017 crude oil sales. Sales to Shell accounted for 13% of our 2017 total crude oil, natural gas and NGL sales, or 22% of crude oil sales. Both BP and Shell purchased crude oil and condensate domestically from our US onshore operations and Gulf of Mexico operations.
No other single purchaser accounted for 10% or more of crude oil, natural gas and NGL sales in 2017. We maintain credit insurance associated with specific purchasers and believe that the loss of any one purchaser would not have a material effect on our financial position or results of operations since there are numerous potential purchasers of our production.
Hedging ActivitiesCommodity prices continue to be volatile and are affected by a variety of factors beyond our control. We use derivative instruments to reduce the impact of commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas. As a result of hedging, a portion of near-term cash flow volatility is reduced.
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 arrangements represent commitments to pay transportation fees, not commitments to deliver minimum volumes to end users.
Regulations
Exploration for, and development, production and marketing of, crude oil, NGLs and natural gas and NGLs are extensively regulated at the federal, state, and local levels in the US, and internationally. Crude oil, natural gas and NGL development and production activities are subject to various laws and regulations (and orders of regulatory bodies pursuant thereto) governing a wide variety of matters, including, among others, allowable rates of production, transportation, prevention of waste and pollution, and protection of the environment. LawsRegulations affecting the crude oil and natural gas industry are under constant review for amendment or expansion over time and frequently impose more stringent requirements on crude oil and natural gas companies.
Our ability to economically produce and sell crude oil, natural gas and NGLs is affected by a number of legal and regulatory factors, including federal, state and local laws and regulations in the US and laws and regulations of foreign nations. Many of theseVarious 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.comply, which may impact our ability to economically produce and sell crude oil, NGLs and natural gas. These laws, regulations and ordersissuances may restrict the rate of crude oil, NGL and natural gas and NGL production below the rate that would otherwise exist in the absence of such laws, regulations and orders. The regulatory requirements on the crude oil and natural gas industry often result in incremental costs of doing business and consequently affect our profitability. See Item 1A. Risk Factors –We are subject to increasing governmental regulations and environmental requirements that may restrict our access to land and/or cause us to incur substantial incremental costs.costs.Internationally, our operations are subject toVarious domestic and international agencies have legal and regulatory authority and oversight byover our exploration for, and production and sale of, crude oil, NGLs and natural gas. Internationally, oversight also includes energy-related ministries or other agencies of our host countries, each having certain relevant energy or hydrocarbons laws. Examples include:
the Ministry of Mines and Hydrocarbons, which, under such laws as the hydrocarbons law enacted in 2006 by the government of Equatorial Guinea, regulates our exploration, development and production activities offshore Equatorial Guinea;
the Ministry of Energy, which regulates our exploration and development activities offshore Israel and the Israeli electricity market into which we sell our natural gas production;
the Israeli Antitrust Commission, which reviews Israel's domestic natural gas sales and ownership in offshore blocks and leases; and
the Ministry of Energy, Commerce, Industry and Tourism, which regulates our exploration and development activities offshore Cyprus.
Examples of US federal agencies with regulatory authority over our exploration for, and production and sale of, crude oil, natural gas and NGLs include:
the Bureau of Land Management (BLM), the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE), which under laws such as the Federal Land Policy and Management Act, Endangered Species Act, National Environmental Policy Act and Outer Continental Shelf Lands Act, have certain authority over our operations on federal lands and waters, particularly in the Rocky Mountains and Gulf of Mexico;
the Office of Natural Resources Revenue, which under the Federal Oil and Gas Royalty Management Act of 1982, has certain authority over our payment of royalties, rentals, bonuses, fines, penalties, assessments, and other revenue;
the US Environmental Protection Agency (EPA) and the Occupational Safety and Health Administration (OSHA), which under laws such as the Comprehensive Environmental Response, Compensation and Liability Act, the Resource Conservation and Recovery Act, the Oil Pollution Act of 1990, the Clean Air Act, the Clean Water Act, the Safe Drinking Water Act, and the Occupational Safety and Health Act have certain authority over environmental, health and safety matters affecting our operations;
the US Fish and Wildlife Service (FWS) and US National Marine Fisheries Service, which under the Endangered Species Act have authority over activities that may result in the take of any endangered or threatened species or its habitat;
the US Army Corps of Engineers, which under the Clean Water Act has authority to regulate the construction of structures involving the fill of certain waters and wetlands subject to federal jurisdiction, including well pads, pipelines and roads;
the Federal Energy Regulatory Commission (FERC), which under laws such as the Energy Policy Act of 2005 has certain authority over the marketing and transportation of crude oil, natural gas and NGLs we produce onshore and from the Gulf of Mexico; and
the Department of Transportation, which has certain authority over the transportation of products, equipment and personnel necessary to our US onshore and Gulf of Mexico operations.
Other US federal agencies with certain authority over our business include the Internal Revenue Service (IRS) and the SEC. In addition, we are governed by the rules and regulations of the NYSE, upon which shares of our common stock 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. 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 habitat, prevention of and responses to leaks and spills, and the remediation of petroleum-product contamination. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, habitat to endangered or threatened species, wetlands, ecologically or seismically sensitive areas, and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations. Where our drilling 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 production from those areas and government agencies frequently add to the lists of protected species.
Under state and federal laws, we could be required to remove or remediate previously disposed wastes, including wastes disposed of or released by us, or by prior owners or operators, in accordance with current laws, to suspend or cease operations in contaminated areas, or to perform remedial well plugging operations or cleanups. The EPAUS 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 are authorized to take actions in response to threats to human health or the environment and to seek to recover from responsible classes of persons the costs of such action. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.
Furthermore, certain wastes generated by our crude oil and natural gas operations that are currently exempt from the definition of hazardous waste may in the future be subject to considerably more rigorous and costly operating and disposal requirements. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Also, in December 2016, the EPA agreed in a consent decree to review its regulation of oil and gas waste. It has until March 2019 to determine whether any revisions are necessary.
Under federal and state occupational safety and health laws, we must develop and maintain information about hazardous materials used, released, or produced in our operations. Certain portions of this information must be provided to employees, state and local governmental authorities, and local citizens. We are also subject to the requirements and reporting set forth in federal workplace standards.
Moreover, certain state or local laws or regulations and common law may impose liabilities in addition to, or restrictions more stringent than, those described herein.
We have made and will continue to make expenditures necessary to comply with environmental requirements. We do not believe that compliance with such requirements will have a material adverse effect on our capital expenditures, earnings or competitive position. Although such requirements do have a substantial impact on the crude oil and natural gas industry, they do not appear to affect us to any greater or lesser extent than other companies in the industry.
The following is a summary of the more significant US environmental developments and requirements that may affect our operations.
Various state and federal statutes such as the Endangered Species Act (ESA) prohibit certain actions that adversely affect endangered or threatened species and their habitat, wetlands, migratory birds, marine mammals, or natural resources. Where the taking or harm of such species occurs or may occur, or where damages to wetlands or natural resources may occur, the government or private parties may act to prevent crude oil and natural gas exploration activities. In particular, a federal or state agency could order a complete halt to drilling activities in certain locations or during certain seasons when such activities could result in a serious adverse effect upon a protected species. The presence of a protected species in areas where we operate could adversely affect future production from those areas and government agencies frequently add to the lists of protected species. For example, listing of the Lesser Prairie Chicken likewise could impact our operations in the Delaware Basin. The Lesser Prairie Chicken was removed from the ESA list of endangered species in July 2016 after a federal court invalidated the FWS’s listing of the bird as threatened because the FWS failed to give proper consideration to voluntary conservation measures; however, the FWS announced in November 2016 an ongoing new status review of the Lesser Prairie Chicken to determine whether listing is still warranted.
The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act” or “CWA,” the Safe Drinking Water Act, the Oil Pollution Act and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters. Provisions of the CWA require authorization from the US Army Corps of Engineers, or the “Corps”, prior to the placement of dredge or fill material into jurisdictional waters. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak.
On June 29, 2015, the EPA and Corps jointly published the final rule defining the scope of the EPA’s and Corps’ jurisdiction, known as the “Clean Water Rule.” The Clean Water Rule has been challenged in multiple federal courts; however, at this time, we cannot predict the outcome of this litigation. Subsequently, the EPA and the Corps proposed a rulemaking in June 2017 to repeal the June 2015 rule, and also announced their intent to issue a new rule defining the Clean Water Act’s jurisdiction. Both agencies also published a proposed rule in November 2017 delaying implementation of the Clean Water Rule for two years. As a result, future implementation of the June 2015 rule is uncertain at this time. To the extent the rule expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to spill prevention, storm water management, and wetlands permitting. We are continuing to monitor the regulatory updates and to evaluate the impact of the new rule on our operations.
Also, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment, or CWT, facilities) accepting oil and natural gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities. In addition, the EPA previously announced its plans to develop a Notice of Proposed Rulemaking by June 2018, which would describe a proposed mechanism - regulatory, voluntary, or a combination of both - to collect data on hydraulic fracturing chemical substances and mixtures.
The federal Clean Air Act, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations.
There also have been a series of recent air regulations and proposals that affect, or that may affect, our operations. In 2012, for example, the EPA issued New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants to control air emissions associated with crude oil, natural gas and NGL production, including natural gas wells that are hydraulically fractured. In addition to addressing emissions from storage tanks and other equipment, those regulations required technologies and processes that, while reducing emissions, enable companies to collect additional natural gas that can be sold. Specifically, as of January 2015, owners and operators of natural gas wells must use emissions reduction technology called “green completions,” technologies that were already widely deployed at wells. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. In response, the EPA has issued, and will likely continue to issue, revised rules responsive to some of the requests for reconsideration. In particular, on May 12, 2016, the EPA amended its regulations to impose new standards for methane and volatile organic compounds emissions for certain new, modified, and reconstructed equipment, processes, and activities across the oil and natural gas sector. However, in a March 28, 2017 executive order, the EPA was directed to review the 2016 regulations and, if appropriate, to initiate a rulemaking to rescind or revise them consistent with the stated policy of promoting clean and safe development of the nation’s energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production. On June 16, 2017, the EPA published a proposed rule to stay for two years certain requirements of the 2016 regulations, including fugitive emission requirements. These standards, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions. To date, these rules have had minimal impact on our business since the reduction of greenhouse gas (GHG) emissions already was one of our priorities and we had been working to improve our methods to reduce GHGs through operational and business practices. For example, we have undertaken emission reduction projects such as our US Vapor Recovery Unit (VRU) program, where we have installed VRUs to capture natural gas that would otherwise be flared on a substantial number of our tank batteries.
Also, on May 12, 2016, the EPA issued a final rule regarding the criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements, which could increase our compliance costs and may require facility siting and design changes.
As another prong of the previous US Administration's methane strategy, on November 15, 2016, the BLM finalized a rule to reduce the flaring, venting and leaking of methane from oil and gas operations on federal and Indian lands. The rule requires operators to use currently available technologies and equipment to reduce flaring, periodically inspect their operations for leaks, and replace outdated equipment that vents large quantities of gas into the air. The rule also clarifies when operators owe the government royalties for flared gas. State and industry groups have challenged this rule in federal court, asserting that the BLM lacks authority to prescribe air quality regulations. On March 28, 2017, the BLM was directed by executive order to review the above rule and, if appropriate, to initiate a rulemaking to rescind or revise it. Accordingly, on December 8, 2017, the BLM published a final rule to suspend or delay certain requirements of the 2016 methane rule until January 17, 2019. Further legal challenges are expected. At this time, it is uncertain when, or if, the rules will be implemented, and what impact they would have on our operations. It also bears noting that substantially all of our US onshore properties are subject to EPA’s requirements for reporting annual GHG emissions. Information in such reports could form the basis of further GHG regulations.
In another air development, the EPA announced in October 2015 that it was lowering the primary national ambient air quality standard for ozone from 75 parts per billion to 70 parts per billion. Implementation will take place over several years; however, areas that cannot meet the new standard eventually will need to impose additional requirements on sources of VOCs and other ozone precursors which could increase the cost of siting and operating our facilities.
Apart from these federal matters, most of the states where we operate have separate authority to regulate operational and environmental matters.
ColoradoIn February 2013,The oil and gas industry is regulated in part by the Colorado Oil and Gas Conservation Commission (COGCC). In December 2018, the COGCC approved an increased setback rulesdistance for crude oil and natural gas wells and production facilities located in close proximity to occupied buildings.schools based on an expanded definition of “school facility.” Previously, the COGCC had allowed uniform setback distances of 150 feet in rural areas and 350 feet in high density urban areas. These have been increased to a uniform 500 feet statewide setback from occupied buildings and 1,000 feet from high occupancy building units. The setback rules also require operators to utilize increased mitigation measures to limit potential drilling impacts to surface owners and the owners of occupied building units. In addition, the rules require advance notice to surface owners, the owners of occupied buildingsbuilding units, and local governments prior to the filing of an Application for Permit to Drill or Oil and Gas Location Assessment as well as outreach and communication efforts by an operator.Assessment.
The COGCC also has implemented rules making Colorado the first state to require sampling of groundwater for hydrocarbons and other indicator compounds both before and after drilling. Those statewide rules require sampling of up to four water wells within a half mile radius of a new crude oil and natural gas well before drilling, between six and 12 months after completion, and between five and six years after completion. For the Greater Wattenberg Area, the COGCC requires operators to sample only one water well per quarter governmental section before drilling and between six to 12 months after completion. Further, the COGCC has adopted rules increasing the maximum penalty for violations of its requirements.
The state environmental agency, the Colorado Department of Public Health and Environment (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 Colorado Department of Public Health and EnvironmentCDPHE has extended the EPA’s emissions standards for crude oil and natural gas operations to directly control methane. The final rules,
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, coverif passed, would have significantly limited, or in some cases prevented, the life cyclefuture 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 development, production, and maintenance, reflect a collaborative effort byrelated regulations could intensify the Environmental Defense Fund, Noble Energy and other oilrisk 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 operators.development activity. Some of the counties and municipalities where we operate in Colorado have adopted their own regulations or ordinances that impose additional restrictions on our crude oil and natural gas exploration and production. To date these have not significantly impacted our operations. However, a few localities in Colorado have tried to prohibit certain exploration and production activities, particularly use of hydraulic fracturing within their boundaries. In May 2016, the Colorado Supreme Court found that the local laws intended to increase regulatory requirements on oil and gas development were preempted by existing state law and were therefore invalid. See Hydraulic Fracturing, below.
In April 2015, we entered into a joint consent decree (Consent Decree) with the EPA, US Department of Justice, and State of Colorado to improve emission control systems at a number of our condensate storage tanks that are part of our upstream 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 of Colorado on June 2, 2015 and requires us to perform certain activities. All fines required under the Consent Decree were paid in 2015; however, the required injunctive relief remains ongoing. BasedWe have concluded that the penalties, injunctive relief, plugging and abandonment activities, and mitigation expenditures that result from this settlement, based on currently available information, we have concluded that the remaining obligations will not have a material adverse effect on our financial position, results of operations or cash flows. See Item 1A. Risk Factors – Our operations require us to comply with a number of US and international laws
Texas Texas has regulations governing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells, the regulation of spacing, and requirements for plugging and abandonment of wells.
In February 2012,The oil and gas industry is regulated in part by the Texas Railroad Commission (RRC) implemented a hydraulic fracturing disclosure rule, requiring. 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 May 2013,addition, the RRC issued an updatedmaintains a “well integrity rule” that addresses requirements for drilling, casing and cementing wells. The rule also includes new testing and reporting requirements, including clarifying that cementing reports must be submitted after well completion or after cessation of drilling, whichever is earlier.
In October 2014, Furthermore, the RRC adopted newoversees permit rules for injection wells to address seismic activity concerns within the state. Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells, and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. The RRC has used this authority to deny permits for waste disposal wells.
US Offshore Regulatory Developments Our operations on federal oil and natural gas leases in the Gulf of Mexico are subject to regulation by BSEE and BOEM. These leases contain relatively standardized terms and require compliance with detailed BSEE and BOEM regulations and orders issued pursuant to various federal laws, including the Outer Continental Shelf Lands Act (OCSLA). These laws and regulations are subject to change, and many new requirements, including those related to safety, permitting and performance, were imposed by BSEE and BOEM subsequent to the April 2010 Deepwater Horizon incident.
In April 2016, the BSEE issued a final rule entitled “Oil and Gas and Sulfur Operations in the Outer Continental Shelf - Blowout Preventer Systems and Well Control,” which updates standards for blowout prevention systems and other well controls for offshore oil and gas activities conducted in US federal waters, including the Gulf of Mexico. The final rule, which went into effect on July 28, 2016, increases the costs associated with well design, drilling and completion operations, as well as ongoing monitoring costs for our wells in the Gulf of Mexico. More recently, pursuant to executive orders dated March 28, 2017, and April 28, 2017, the BSEE initiated a review of whether the final rule is consistent with the stated policy of encouraging energy exploration and production, while ensuring that any such activity is safe and environmentally responsible. On October 24, 2017, the BSEE announced - in a report published by the Department of Interior - that it is considering several revisions to the rule and that it is in the process of determining the most effective way to engage stakeholders in the process.
Also, in April 2016, the BOEM published a proposed air quality rule that would significantly broaden the obligations of operators and lessees in the Outer Continental Shelf, including the Gulf of Mexico, to assess, report and, when appropriate, control emissions. Among other items, the proposed rule would expand the types of emissions that must be measured, change the boundary for evaluating air emissions, and increase the scope of sources that must be addressed. If adopted as proposed, the new rule would likely increase the cost associated with our activities in the Gulf of Mexico. Pursuant to the Executive Orders, the BOEM is reviewing the proposed air quality rule. On October 24, 2017, the Department of Interior announced that it is currently reviewing recommendations on how to proceed, including promulgating final rules for certain necessary provisions and issuing a new proposed rule that may withdraw certain provisions and seek additional input on others.
Additionally, in order to cover the various decommissioning obligations of lessees on the OCS, the BOEM generally requires that lessees post some form of acceptable financial assurances that such obligations will be met, such as surety bonds. The BOEM recently updated its regulations and program oversight to establish more robust risk management, financial assurance and loss prevention requirements for oil and gas operations in the Outer Continental Shelf, including the Gulf of Mexico. On July 14, 2016, the BOEM issued an updated Notice to Lessees and Operators (NTL) providing details on revised procedures the agency will be using to determine a lessee’s or operator's ability to carry out decommissioning obligations for activities in the Outer Continental Shelf, including the Gulf of Mexico. This revised policy institutes new criteria by which the BOEM will evaluate the financial strength and reliability of lessees and operators active in the Outer Continental Shelf. If the BOEM determines under the revised policy that a lessee or operator does not have the financial ability to meet its decommissioning and other obligations, that lessee or operator will be required to post additional financial security as assurance. The revised policy originally became effective September 12, 2016; however, the BOEM extended the implementation timeline for six months in certain circumstances. Pursuant to the Executive Orders, the BOEM is reviewing the NTL to determine whether modifications are necessary to ensure operator compliance with lease terms while minimizing unnecessary regulatory burdens. On June 22, 2017, the BOEM announced that, pending its review of the NTL, the implementation timeline would be indefinitely extended, subject to certain exceptions. We estimated the impact of the new financial criteria on our operations in the Gulf of Mexico and do not believe that the revised policy will have a material impact on our operations in the Gulf of Mexico, or on our financial position or cash flows.
The National Oceanic and Atmospheric Administration (NOAA) is proposing to expand the boundaries of the Flower Garden Banks National Marine Sanctuary in the Gulf of Mexico. NOAA released its draft environmental impact statement (DEIS) on the proposed expansion in June 2016, in which it proposed five alternatives for expanding existing sanctuary regulations to new geographic areas. Two of these alternatives for sanctuary expansion have the potential to impact certain of our leases which could increase drilling, operating and decommissioning costs. The comment period for the expansion alternatives outlined in the DEIS expired on August 19, 2016 and the issuance of NOAA's report recommending alternatives is expected in early 2018. We are currently evaluating the expansion alternatives and assessing any potential impact on our operations in the Gulf of Mexico.
Climate Change In recent years, the EPA has finalized a series of greenhouse gas (GHG) gas monitoring, reporting and emissions control rules for the oil and natural gas industry, and the US Congress has, from time to time, considered adopting legislation to reduce emissions. In addition, almost one-half of the states have already taken measures to reduce emissions of greenhouse gasesGHGs primarily through the development of greenhouse gasGHG emission inventories and/or regional greenhouse gasGHG cap-and-trade programs.
At the international level, in December 2015, the United StatesUS signed the Paris Agreement on climate change and pledged to take efforts to reduce GHG emissions and to conserve and enhance sinks and reservoirs of GHGs. The Paris Agreement entered into force in November 2016. However, in August 2017, the United StatesUS notified the United Nations that it would be withdrawing from the Paris Agreement and begin negotiations to either re-enter or negotiate an entirely new agreement with more favorable terms for the United States.US. The Paris Agreement sets forth a specific exit process, whereby a party may not provide notice 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.
The current state of development of the ongoing international climate initiatives and any related domestic actions make it difficult to assess the timing or effect on our operations or to predict with certainty the future costs that we may incur in order to comply with future international treaties, legislation or new regulations. However, future restrictions on emissions of GHGs, or related measures to encourage use of renewable energy could have a significant impact on our future operations and reduce demand for our products. See also Items 1. and 2. Business and Properties - Regulations and Item 1A. Risk Factors. Impact of Dodd-Frank Act Section 1504In June 2016, the Securities and Exchange Commission (SEC) adopted resource extraction issuer payment disclosure rules under Section 1504 of the Dodd-Frank Act that would have required resource extraction companies, such as us, to publicly file with the SEC beginning in 2019 information about the type and total amount of payments made to a foreign government, including subnational governments (such as states and/or counties), or the US federal government for each project related to the commercial development of crude oil, natural gas or minerals, and the type and total amount of payments made to each government (such rules, the Resource Extraction Issuer Payment Rules).
However, on February 14, 2017, through the signing of a joint resolution passed by the United States Congress under the Congressional Review Act, the Resource Extraction Issuer Payment Rules were eliminated. It should be noted that Section 1504 of the Dodd-Frank Act has not been repealed and that the SEC will now have until February 2018 to issue replacement rules to implement Section 1504 of the Dodd-Frank Act, and that under the Congressional Review Act a rule may not be issued in “substantially the same form” as the disapproved rule unless it is specifically authorized by a subsequent law. We cannot predict whether the SEC will issue replacement rules or, if it does so, whether such replacement rules will again be eliminated pursuant to the Congressional Review Act.
Israel Regulatory Environment
Natural Gas Policy and Antitrust AuthorityThe 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 providesprovided 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 8. Financial Statements and Supplementary Data – Note 4.5. Acquisitions Divestiture and Merger.DivestituresIsraeli Tax LawEffective December 21, 2016, the Israeli government decreased the corporate income tax rate from 25% to 24% for 2017 and announced a further rate decrease from 24% to 23% effective January 2018. The change decreased the deferred tax expense for 2017 by $12 million. Furthermore, our Israeli operations are subject to the Natural Resources Profits Taxation Law, 2011, which imposes a separate additional tax on profits from oil and gas activities (Profits Tax). See Item 8. Financial Statements and Supplementary Data – Note 11. Income Taxes.Hydraulic Fracturing
Hydraulic fracturing techniques have been used for decades on the majority of all new onshore crude oil and natural gas wells drilled domestically. The process involves the injection of water, sand and chemical additives under pressure into targeted subsurface formations to stimulate oil and gas production. We strive to adopt best practices and industry standards and comply
with all regulatory requirements regarding well construction and operation. For example, the qualified service companies we use to perform hydraulic fracturing, as well as our personnel, monitor rate and pressure to assure that the services are performed as planned. Our well construction practices include installation of multiple layers of protective steel casing surrounded by cement that are specifically designed and installed to protect freshwater aquifers by preventing the migration of fracturing fluids into those aquifers. To help reduce our operational demand for freshwater and need for disposal, we are currently developing technology and infrastructure to expand our water recycling capacity in the DJ and Delaware Basins. We believe that these processes help ensure hydraulic fracturing is safe and does not and will not pose a risk to water supplies, the environment or public health.
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. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the Underground Injection Control program, specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act. In addition, the EPA previously announced its plans to develop a Notice of Proposed Rulemaking by June 2018, which would describe a proposed mechanism - regulatory, voluntary, or a combination of both - to collect data on hydraulic fracturing chemical substances and mixtures.process;
In addition, on March 26, 2015, 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. The rule requires public disclosure of chemicals used in hydraulic fracturing, implementation of a casing and cementing program, management of recovered fluids, and submission to the BLM of detailed information about the proposed operation, including wellbore geology, the location of faults and fractures, and the depths of all usable water. On June 21, 2016, the United States District Court for Wyoming set aside the rule, holding that the BLM lacked Congressional authority to promulgate the rule. The BLM has appealed the decision to the Tenth Circuit Court of Appeals. On March 28, 2017, an executive order was signed, directing the BLM to review the rule and, if appropriate, to initiate a rulemaking to rescind or revise it. Accordingly, on December 29, 2017, the BLM published a final rule to rescind the 2015 hydraulic fracturing rule. Further legal challenges are expected. At this time, it is uncertain when, or if, the rules will be implemented, and what impact they would have on our operations.expected;
Furthermore, governments and agencies at all levels from federal to municipal are studying the potential environmental impacts of hydraulic fracturing and evaluating the need for further requirements. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing, and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.
In June 2012, OSHA and the National Institute of Occupational Safety and Health (NIOSH) issued a joint hazard alertAdministration (OSHA) has lowered exposure limits for workers who use silica (sand) in hydraulic fracturing activities. The following year saw the agency formally propose to lower the permissible exposure limit for airborne silica. In 2016, OSHA finalized a lower exposure limit for silica along with stricteractivities, and silica work practices. For hydraulic fracturing, the new obligations start to take effect in 2018. OSHA also has prepared guidance identifying additional workplace hazards resulting from hydraulic fracturing and ways to reduce exposure to those hazards.practices have become stricter;
To date, hydraulic fracturing has been regulated primarily at the state level, and all of the states where our US onshore operations are located (including Colorado and Texas) have developed such requirements. See Regulations - Colorado and Texas, above. Also, state and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for oil and gas waste disposal and seismic activity, which some have termed "induced seismicity." In a few instances, operators of injection wells in the vicinity of seismic events have been ordered to reduce injection volumes or suspend operations. Some“induced seismicity,” and some state regulatory agencies have modified their regulations to account for such induced seismicity with regardseismicity; andongoing or proposed studies on the environmental impacts of hydraulic fracturing could spur initiatives to the operation of injection wells used for oil and gas waste disposal. Increased regulation and attention given to induced seismicity in the states where we operate could lead to greater opposition, including litigation, to oil and gas activities utilizing injection wells for waste disposal. further regulate hydraulic fracturing.
Several states, including Colorado and Texas, have adopted regulations requiring disclosure of certainWe currently disclose information regarding the components and chemicals used in the hydraulic-fracturing process. These state regulations allow disclosureprocess for all US onshore areas in which we operate through the website for the public registry FracFocus.org, which is operated jointly by the Interstate Oil & Gas Compact Commission and the Ground Water Protection Council. Disclosure through the FracFocus web site includes ways to protect proprietary information
Additional InformationSee:
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 partythird-party liability, worker's compensation insurance and certain insurance related to cyber security. We maintain insurance at levels that we believe are appropriate and consistent with industry practice and wepractice. 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, however, actively looking to secure additional coverages for political risks in Jordan and Egypt. In Israel and Equatorial Guinea, we insure against acts of war and terrorism in addition to providing insurance coverage for normal operating hazards facing our business. Additionally, as being part of
critical national infrastructure, the Israel offshore and onshore assets are included in a special property coverage afforded under the Israeli government's Property Tax and Compensation Fund Law; however, the amount of financial recovery through the fund is not guaranteed.
We have a risk assessment program that analyzes safety and environmental hazards, including cyber threats, and establishes procedures, work practices, training programs and equipment requirements, including monitoring and maintenance rules, for continuous improvement. We also use third partythird-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. Undeveloped Oil and Gas LeasesCompetition
Oil and gas exploration is a lengthy process of obtaining data, evaluating, and de-risking prospects, and it takes time to develop resources in a responsible manner. The period of time from lease acquisition to discovery can take many years of ongoing effort.
We begin by leasing acreage (or deepwater lease blocks) from individuals, other operators or the host government. It may take years for us to assemble sufficient acreage to cover the areal extent of a prospect that we wish to explore.
Once the acreage position is assembled, we obtain seismic data either through purchase of available data or by contracting for seismic services. Our exploration staff then begin a lengthy process of analyzing the seismic and other data in order to identify a potential optimal location for drilling an initial exploratory well. Once we decide to drill an exploratory well, we must obtain permits and contract a drilling rig with the specifications for the depth and well pressures which we expect to drill.
If there is a discovery, we may need to obtain additional data and/or drill appraisal wells in order to estimate the extent of the reservoir and the volume of resources that could potentially be recovered. Appraisal or development drilling requires additional time to contract for an appropriate drilling rig, and obtain pipe, other equipment, and supplies.
Competition
The crude oil and natural gas industry is highly competitive. We encounter competition from other crude oil and natural gas companies in all areas of operations, including the acquisition of seismic data and lease rights on crude oil and natural gas properties and for the labor and equipment required for exploration and development of those properties. Our competitors include major integrated crude oil and natural gas companies, state-controlled national oil companies, independent crude oil and natural gas companies, service companies engaging in exploration and production activities, drilling partnership programs, private equity, and individuals. Many of our competitors are large, well-established companies. Such companies may be able to pay more for seismic information and lease rights on crude oil and natural gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.
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 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, natural gas or NGLs.
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, 2017,2018, we had 2,2772,330 full-time employees.
Offices
Our principal corporate office is located at 1001 Noble Energy Way, Houston, Texas, 77070. We maintain additional regional exploration and/or production offices primarily in Denver, Colorado; Greeley, Colorado; Pecos, Texas; Dilley, Texas; and inthe US, Israel, Cyprus, Egypt, Equatorial Guinea, and Equatorial Guinea.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 the majority of our DJ Basin assets are primarily held by production, certain of ourother 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 and failureor exercise options with land owners to extend leases. Failure to meet these obligations may result in the loss of a lease.
Title DefectsSubsequent 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 RightsMineral 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”,Charters,” and available in print upon request made by any stockholdershareholder to the Investor Relations Department, are charters for our Audit Committee, Compensation, Benefits and Stock Option Committee, Corporate Governance and Nominating Committee, and Environment, HealthSafety, Sustainability and SafetyCorporate 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, as applicable, we will post on our website any modifications to the Codes and any waivers applicable to senior officers as defined in the applicable Code, as required by the Sarbanes-Oxley Act of 2002.
Item 1A. Risk Factors
Described below are certain risks that we believe are applicable to our business and the oil and gas industry in which we operate. There may be additional risks that are not presently material or known. You should carefully consider each of the following risks and all other information set forth in this Annual Report on Form 10-K.
If any of the events described below occur, our business, financial condition, results of operations, cash flows, liquidity or access to the capital markets could be materially adversely affected. In addition, the current global economic and political environment intensifies many of these risks.
The oil and gas industry is cyclical and an extended period of suppressed commoditycrude oil, NGL and natural gas prices are volatile. A reduction in these prices could have a material adverse effectseffect on our operations, our liquidity, and the price of our common stock.
Our ability to operate profitably, maintain adequate liquidity, grow our cash flow and pay dividends onor repurchase our common stock depend upon the prices we receive for our crude oil, NGL and natural gas and NGL production. Commodity prices are cyclical and subject to global supply and demand dynamics. For the past three years, following the significant
A prolonged or substantial decline that began in late 2014, crude oil prices, in particular, have been trading in a much lower range. While we have witnessed a certain degree of commodity price improvement, we expect that economic, geopolitical, and supply and demand forces will remain volatile. As a
result we may continue to operate in a soft market, with sustained lower commodity prices, subject to further decline if the excess of supply over demand increases.
Ifincluding declines in commodity prices continue to trade at lowforward price curves or lower levels for an extended period, one or more ofvolatility in location-basis differentials, may have the following could occur:effects on our business:
significant reductionsreduction of our revenues, profit margins, operating income and cash flows;
reduction in the amount of crude oil, NGLs and natural gas and NGLs 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;
loss of undeveloped acreage if our production is shut-in or we are unable to make scheduled delay rental payments;
use of cash flow to satisfy minimum obligations under throughput agreements if production is suspended;
reduction, or suspension, of our 2018 or future capital investment programs, resulting in a reduced ability to develop 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 capital 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;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; and
reduction or suspension of dividends onor repurchases of our common stock.
In addition, lower commodity prices, including declines in commodity forward price curves, may result in the following:stock;
declines in our stock price;
additional counterparty credit risk exposure on commodity hedges and joint venture receivables; and
a reduction in the carrying value of goodwill.
Our 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 price volatility.
Furthermore, certain crude oil demand estimates suggest a hypothetical point in the future when global oil demand reaches its peak demand level. The International Energy Agency's 450 Scenario sets out an energy pathway consistent with the goal of limiting the global increase in temperature to 2°C by limiting concentration of greenhouse gases in the atmosphere to around 450 parts per million of CO2. Under this scenario, global oil demand peaks by 2020, and the subsequent decline in demand accelerates year-on-year, so that by the late 2020s global demand is falling by over one million barrels per day every year. This decline in demand, if it occurs, would negatively impact commodity prices as well as our ability to explore for and develop our crude oil and natural gas resources.prices.
Markets and prices for crude oil, NGLs and natural gas and NGLs depend on factors beyond our control, factors including, among others:
global demand for crude oil, NGLs and natural gas, and NGLs as impacted by economic factors that affect gross domestic product growth rates of countries around the world;
global supply for crude oil, NGLs and natural gas, and NGLs as impacted by OPEC and non-OPEC countries (e.g. US, Russia, Canada);
technology advances that increase crude oil, NGL and natural gas and NGL 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;
developments in the global LNG market, including exports from the US;
geopolitical conditions and events, including generational leadership or regime changes, changes in government energy policies, including imposed price controls and/or product subsidies, or instability/armed conflict in hydrocarbon-producing regions;
fluctuations in US dollar exchange rates, the currency in which the world's crude oil trade is generally denominated;
the price and availability of alternative fuels including coal, solar, wind, nuclear energy and biofuels, as well as the availability of battery storage;
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;
fuel efficiency regulations, such asdevelopments in the Corporate Average Fuel Economy (CAFE) standards,global LNG market, including exports from the US;
geopolitical conditions and its impacts on demand forevents, including 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 ais currently the case in the Delaware Basin, which in turn results in transportation fuel;
the availability of pipeline capacity/infrastructure as well as refining capacity;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 partythird-party oilfield equipment materials service and supplyservice 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.
During 2017, increasesAs 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 completion activity resultedoperating 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 higher demand for oilfield services.certain basins. As a result, the costs of drilling, equippingthere is pressure on operating margins and operating wells and infrastructure began to experience some inflation. capital efficiency in US onshore basins, including those in which we operate.
If this trend continues, and if the commodity price recovery is robust,prices increase, we expect industry exploration and production activities to continue to increase, resulting in even higher demand for oilfield equipment services, and supplies, which could result in significant sector price inflation. In addition, the costs of such items could increase and their availability may become limited, particularly in basins of relatively higher activity. Potentialactivity, scarcity of competent service personnel may impact our ability to execute our exploration and development plans in a timely and profitable manner.
In addition, regulatory changes, such as those related to hydraulic fracturing or water disposal, may also resultConcentration of capital in, reduced availability and/or higher costs for rigs and services. As a result, drilling rigs and oilfield services may not be available at rates that provide a satisfactory return on our investment.
Our international operations may be adversely affected by economic and geopolitical developments.
We have significant international operations, with approximately 27% of our 2017 total consolidated sales volumes and approximately 52% of our total proved reserves as of December 31, 2017 attributable to our international operations in Israel and Equatorial Guinea. We also conduct exploration activities in other international areas. Our operations may be adversely affected by political and economic developments, including the following:
renegotiation, modification or nullification of existing contracts, such as may occur pursuant to future regulations enacted as a result of changes in Israel's antitrust, export and natural gas development policies, or the hydrocarbons law enacted in 2006 by the government of Equatorial Guinea, which can result in an increase in the amount of revenues that the host government receives from production (government take) or otherwise decrease project profitability;
loss of revenue, property and equipment as a result of actions taken by host nations, such as expropriation or nationalization of assets or termination of contracts;
disruptions caused by territorial or boundary disputes in certain international regions;
changes in drilling or safety regulations;
laws and policies of the US and foreign jurisdictions affecting trade, foreign investment, taxation and business conduct;
potential for Israel natural gas production and regional exports to be interrupted by political conditions and events, and regional instability or armed conflict in the region;
difficulties enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations;
US and international monetary policies impacting foreign exchange or repatriation restrictions in countries in which we conduct business;
war, piracy, acts of terrorism or civil unrest; and
other hazards arising out of foreign governmental sovereignty over areas in which we conduct operations.
Such political and economic developments could have a negative impact on our results of operations and cash flows and reduce the fair values of our properties, resulting in impairment charges.
Ourfrom, certain operations may be adversely affected by changes in the fiscal regimes and related government policies and regulations in the countries in which we operate.increase our exposure to risks enumerated herein.
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, aA significant portion of our production comesand revenues is highly concentrated and is generated from a limited number of conventional deepwater wells. These wells, located offshore Israel and offshore Equatorial Guinea; therefore, changes in or uncertainties relatedGuinea, contributed approximately 20% of our 2018 total crude oil, NGL and natural gas revenues and 26% of our 2018 total consolidated sales volumes. In
addition, we have a significant impact onmajor concentration of reserves offshore Israel, with approximately 43% of our operations and financial performance. Further,year-end 2018 proved reserves attributable to this area.
Although we cannot predict how government agencies or courts will interpret existing regulations and tax laws or the effect such interpretations could have on our business.
Many governments globally are seeking additional revenue sources, including, potentially, increases in government financial take from oil and gas projects. In developing nations, governments may seek additional revenues to support infrastructure and economic development andcarry contingent business interruption insurance for social spending. In many nations of the Organisation for Economic Cooperation and Development (OECD), governments continue to incur significant budget deficits and growing national debt levels,these producing assets, as well as pressure from financial marketsother insurance, the insurance is insufficient to address structural spending imbalances.cover all potential risks.
The OECD Base ErosionWe also have significant concentrations of capital and Profit Sharing (BEPS) initiative aimsproduction in unconventional basins including the DJ Basin, Delaware Basin and Eagle Ford Shale, and we expect to standardizeinvest approximately 70% of our total capital investment program to development activities in these areas in 2019. Restrictions in land access or permitting, rapid changes in drilling and modernize global tax policycompletion technology, significant increases in drilling and disclosurecompletion costs, lack of financialavailability of downstream services, including access to gathering facilities, transportation and/or takeaway pipelines, lack of reliable power or electricity infrastructure, changes in regulations and operational data with tax authorities. The BEPS's recommendations are being widely adopted by the majority of the foreign jurisdictionsother risks impacting these areas, as enumerated in which we operate and many of these jurisdictions are party to the Multilateral Convention to Implement Tax Treaty Related Measures to Prevent Base Erosion and Profit Shifting. Progress on the implementation of BEPS measures and development of tax authority interpretation could result in changes to tax policies, including transfer pricing policies. To the extent such changes significantly increase the overall tax imposed on currently producing projects, these projects could become less economic, or wholly uneconomic, thereby reducing the amount of proved reserves we record and cash flows we receive, and possibly resulting in asset impairment charges.
Changes in fiscal regimescertain risk factors described herein, can have long-termimmediate, significant negative impacts on our business strategy, and fiscal uncertainty makes it difficult to formulate and execute capital investment programs. The implementation of new, or the modification of existing, laws or regulations increasing the tax costs on our business could disrupt our business plans and negatively impact our operations and our stock price in the following ways, among others:
restrict resource access or investment in lease holdings;
limit or cancel exploration and/or development activities, which could have a long-term negative impact on the quantities of proved reserves we record and inhibit future production, growth;
have a negative impact on the ability of us and/or our partners to obtain financing;
reduce the profitability of our projects, resulting in decreases in net income and cash flows with the potential to make future investments uneconomical;
result in currently producing projects becoming uneconomic, to the extent fiscal changes are retroactive, thereby reducing the amount of proved reserves we record and cash flows we receive, and possibly resulting in asset impairment charges;
require that valuation allowances be established against deferred tax assets, with offsetting increases in income tax expense, resulting in decreases in net income and cash flow; and/or
restrict our ability to compete with imported volumes of crude oil or natural gas.
Tax laws and regulations may change over time, and could adversely affect our business and financial condition.
On December 22, 2017, the US Congress enacted the Tax Cuts and Jobs Act (Tax Reform Legislation). The Tax Reform Legislation, among other things, (i) permanently reduces the US corporate income tax rate to 21% beginning in 2018, (ii) repeals the corporate alternative minimum tax (AMT) allowing for corresponding refunds of prior period AMT credits, (iii) provides for a five year period of 100% bonus depreciation followed by a phase-down of the bonus depreciation percentage, (iv) imposes a new limitation on the utilization of net operating losses generated in taxable years beginning after December 31, 2017, and (v) provides for more general changes to the taxation of corporations, including changes to the deductibility of interest expense, the adoption of a modified territorial tax system, assessing a repatriation tax or “toll-charge” on undistributed earnings and profits of US-owned foreign corporations, and introducing certain anti-base erosion provisions. The Tax Reform Legislation is complex and far-reaching and could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development, or increase costs. The ultimate impact of the Tax Reform Legislation may differ from our estimates due to changes in interpretations and assumptions made by us as well as additional regulatory guidance that may be issued, and our business and financial condition could be adversely affected.
In addition, from time to time, legislation has been proposed that, if enacted into law, would make significant changes to US federal and state income tax laws, including (i) the elimination of the immediate deduction for intangible drilling and development costs, (ii) the repeal of the percentage depletion allowance for oil and natural gas properties; and (iii) an extension of the amortization period for certain geological and geophysical expenditures. While these specific changes are not included in the Tax Reform Legislation, no accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future, or the timing of any such action. The elimination of such US federal tax deductions, as well as any other changes to or the imposition of new federal, state, local or non-US taxes (including the imposition of, or increases in production, severance or similar taxes) could adversely affect our business and financial condition.
We are subject to increasing governmental regulations and environmental requirements that may cause us to incur substantial incremental costs.
Our industry is subject to complex laws and regulations adopted or promulgated by international, federal, state and local authorities relating to the exploration for, and the development, production and marketing of, crude oil, natural gas and NGLs. As the various government and/or regulatory bodies issue or rescind various regulations, our operations are subject to significant volatility in response to the issuance, interpretation and application of these regulations.
Changes in price controls, taxes and environmental laws relating to our industry have the ability to substantially affect crude oil, natural gas and NGL production, operations and economics. Environmental laws, in particular, can change frequently, often become stricter and at times may force us to incur additional costs as changes are implemented.
We cannot always predict with certainty how agencies or courts will interpret existing laws and regulations or the effect these interpretations may have on our business or financial condition.
Additionally, the unintentional discharge of natural gas, crude oil, or other pollutants into the air, soil or water may give rise to liabilities on our part to government agencies and/or third parties, and may require us to incur costs to achieve remediation objectives and/or requirements.
In April 2015, for example, we entered into a Consent Decree with the US EPA, US Department of Justice and State of Colorado to improve emission control systems at a number of our condensate storage tanks in the DJ Basin. The Consent Decree required us to pay a civil penalty and to perform certain injunctive relief activities, mitigation projects, and supplemental environmental projects. We continue to incur costs associated with these activities. In addition, compliance with the Consent Decree could result in the temporary shut in or permanent plugging and abandonment of certain wells and associated tank batteries within the Non-Attainment Area of the DJ Basin.
Noncompliance with existing or future legislation or regulations could potentially result in an increased risk of civil or criminal fines or sanctions. For example, fines or sanctions associated with a well incident or spill could well exceed the actual cost of containment and cleanup.
Further expansion of environmental, safety and performance regulations or an increase in liability for drilling or production activities, including punitive fines, may have one or more of the following impacts on our business:
increase the costs of drilling exploratory and development wells;
cause delays in, or preclude, the development of our projects resulting in longer development cycle times;
result in additional operating and capital costs;
divert our cash flows from capital investments in order to maintain liquidity;
increase or remove liability caps for claims of damages from oil spills;
increase our share of civil or criminal fines or sanctions for actual or alleged violations if a well incident were to occur; and
limit our ability to obtain additional insurance coverage, at a level that balances the cost of insurance and our desired rates of return, to protect against any increase in liability.
Any of the above operating or financial factors may result in a reduction of our cash flows, profitability and the fair value of our properties or reduce our financial flexibility. Because we strive to achieve certain levels of return on our projects, an increase in our financial responsibility could result in certain of our planned projects becoming uneconomic. See Items 1. and 2. Business and Properties – Regulations.position.We face various risks associated with global populism and general political uncertainty.
Following the 2008/2009 global financial crisis, the world has experienced lower economic growth versus the levels attained in previous decades. This has resulted in economic stagnation for certain citizens and, as a result, there are concerns around jobs, economic well-being and wealth distribution. Globally, certain individuals and organizations are attempting to focus the public's attention on income and wealth distribution and implement income and wealth redistribution policies.
In addition, if efforts to challenge and change individual and/or corporate taxation are successful, they could result in increased taxation on individuals and/or corporations, as well as, potentially, increased regulation on companies and financial institutions. These measures would further burden companies and individuals with additional tax costs.
Recent events have intensified these risks. In the US, the growing trends toward populism and political polarization, has resulted in uncertainty regarding potential changes in regulations, fiscal policy, social programs, domestic and foreign relations and international trade policies. Global uncertainty and/or reductions in global trade activities could contribute to slower economic growth which could negatively impact business and commerce.
Potential changes in relationships among the US, China and Russia, or among China, Russia and other countries, can have significant impacts on the balance of power, as well as on global trade, with further impacts on both global and local
economies. In addition, changes in the relationships between the US and its neighbors, such as Mexico, can have significant, potentially negative, impacts on commerce. In Europe, the populist movement has resulted in the Brexit vote and increasing populist demands and rises in nationalism could have a negative impact on economic policy and consequently pose a potential threat to the unity of the European Union.
Our ability to respond to these developments or comply with any resulting new legal or regulatory requirements, including those involving economic and trade sanctions, as well as any potential increased tax expense, could reduce our ability to negotiate the sale of our products, increase our costs of doing business, reduce our financial flexibility and otherwise have a material adverse effect on our business, financial condition and results of our operations.
We face various risks associated with the trend toward increased anti-oil and gas development activity.
In recent years, we have seen significant growth in opposition to oil and gas development both in the US and globally.
Companies in our industry can be the target of opposition to hydrocarbon development from stakeholder groups, including national, state and local governments, regulatory agencies, non-government organizations and public citizens. This opposition is focused on attempting to limit or stop hydrocarbon development.development in certain areas. Examples of such opposition include: efforts to reduce access to public and private lands; delaying or canceling permits for drilling or pipeline construction; limiting or banning industry techniques such as hydraulic fracturing, and/or adding restrictions on or the use of water and associated disposal; imposition of set-backs on oil and gas sites; delaying or denying air-quality permits; advocating for increased regulations, punitive taxation, or citizen ballot initiatives or moratoriums on industry activity; and the use of social media channels to cause reputational harm.
We have experienced these efforts in Colorado, 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 oil and gas development in the State. 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.
Recent efforts by the US Administration to modify federal oil and gas related regulations could intensify the risk of anti-development efforts from grass roots opposition.
Our need to incur costs associated with responding to these anti-development efforts, including legal challenges, or complying with any new legal or regulatory requirements resulting from these efforts, could have a material adverse effect on our business, financial condition and results of operations.
Restricted land access could reduceDiscoveries or acquisitions of reserves are needed to avoid a material decline in reserves and production.
The production 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 ability to explore forestimated proved reserves and developfuture crude oil, NGL and natural gas production will decline materially as reserves are produced unless we conduct successful exploration and NGL reserves.
Our ability to adequately explore for and develop crude oil, natural gas and NGL resources is affected by a number of factors related to access to land. Examples of factors which reduce our access to land include, among others:
new municipal, state or federal land use regulations, which may restrict drilling locations or certaindevelopment activities, such as hydraulic fracturing;
local and municipal government control of landidentifying additional producing zones in existing fields, utilizing secondary or zoning requirements, which can conflict with state law and deprive land owners of property development rights;
landowner, community and/tertiary recovery techniques or governmental opposition to infrastructure development;
regulation of federal and Indian land by the BLM;
anti-development activities, which can reduce ourgaining access to leasesproperties 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 marketability of our production is dependent upon access to gathering, transportation and processing 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 capacity of gathering systems, transportation pipelines, rail service, and processing facilities. We deliver crude oil, NGLs and natural gas produced from these areas through legal challengesmidstream infrastructure, the majority of which we do not own and may not control.
We currently rely on state-owned pipeline and transportation systems to deliver our natural gas production from offshore Israel to customers and end users in the region. In addition, with the execution of multiple agreements 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 2019 and is pending certain conditions precedent. Offshore Equatorial Guinea, our natural gas production is delivered to onshore processing and storage facilities operated by our partner, and the resulting products, as well as our crude oil production from Aseng and Alen, are lifted to tankers owned by third-parties.
Third-party systems and facilities may not be available to us in the future at a price that is acceptable to us. In addition, the lack of availability of, or lawsuits, disruption of drilling, or damage to equipment;
capacity on, third-party systems and facilities, including those owned by Noble Midstream Partners, could reduce the presence of threatened or endangered species or of their habitat;
disputes regarding leases; and
disputes with landowners, royalty owners, or other operators over such matters as title transfer, joint interest billing arrangements, revenue distribution, orprice offered for our production or cost sharing arrangements.
Lossresult in the shut-in of accessproducing wells or the delay or discontinuance of development plans for properties. Further, the inability of third-party processors, over whom we have no control, to land for which we own mineral rightsmeet anticipated facility expansion deadlines, or to delay or even cancel projects, in areas where our production is growing, 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 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 and, in turn, our results of operations, cash flows, and financial condition.
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 economic or political developments, including the following:
renegotiation, modification or nullification of existing contracts, which may occur pursuant to future regulations enacted as a reductionresult 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;
changes in drilling or safety regulations;
laws and policies of the US and foreign jurisdictions affecting trade, foreign investment, taxation and business conduct;
potential for Israel natural gas production and regional exports to be interrupted by political conditions and events;
difficulties enforcing our proved reservesrights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations;
US and international monetary policies impacting foreign exchange or repatriation restrictions in countries in which we conduct business; and
other hazards arising out of foreign governmental sovereignty over areas in which we conduct operations.
Such economic and political developments could have a negative impact on our results of operations and cash flows. Reducedflows and reduce the fair values of our properties, resulting in impairment charges.
In addition, our international operations are located in, or 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 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 obtain new leasesmitigate their impact.
Civil disturbances, terrorist acts, regime changes, war, or conflicts, or the threats thereof, could constrainhave the following results, among others:
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 future growthproducts;
negative impact on the global crude oil supply if infrastructure or transportation are disrupted, leading to further commodity price volatility;
difficulty in attracting and opportunity set by limiting the expansionretaining qualified personnel to work in areas with potential for conflict;
inability of our upstream portfolio. In addition, losspersonnel, third-party providers or supplies to enter or exit the countries where we conduct operations;
disruption of rights granted under surface use agreements, rights-of-way, surface leasesour 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 easement rights, could disruptoperating assets;
damage to or prohibitdestruction of property belonging to our abilitypurchasers, leading to construct interruption of commodity deliveries, claims of force majeure, and/or operate midstream assets and could havetermination of sales contracts, resulting in a material adverse effect onreduction in our revenues;
lack of availability of drilling rigs, oilfield equipment or services if third-party providers decide to exit the region;
shutdown of a financial system, communications network, or power grid causing a disruption to our business financial condition, resultsactivities; and
capital market reassessment of operations,risk and cash flows.reduction of available capital making it more difficult for us and our partners to obtain financing for potential development projects.
A change in internationalLoss of property and/or US federal and state climate policy could have a significant impact oninterruption of our operations and profitability.
Domestic and international response to climate and related energy issues are matters of public policy consideration. We are currently in a period of increasing uncertainty as to these matters, and, at this time, it is difficult to anticipate howbusiness plans resulting from civil disturbances, terrorist acts, regime changes, war, or conflicts, or the current US Administration, or other entities, may act on exiting or new laws and regulations. As compared with certain large multi-national, integrated energy companies, we do not conduct fundamental research regarding the scientific inquiry of climate change. However, we will continue to closely monitor all relevant developments in this regard. Changes in international, federal or state laws and regulations regarding climate policythreats thereof, could have a significant negative impact on our ability to explore forearnings 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 states in the US have taken measures to reduce emissions of greenhouse gases primarily through the development of greenhouse gas emission inventories and/or regional greenhouse gas cap-and-trade programs. For a description of existing and proposed greenhouse gas rules and regulations, see Items 1. and 2. Business and Properties - Regulations.cash flow. In addition, claimswe may not 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 individualsenough insurance to cover any loss of property or other entities may make claims against us for alleged personal injury, property damage, or other potential liabilities. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could impact our operations and could have an adverse impact on our financial condition.
Moreover, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially hotter or colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured.these risks.
Our Eastern Mediterranean discoveries bear certain technical, geopolitical, regulatory, financial and technicalfinancial challenges that could adversely impact our ability to monetize these natural gas assets.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 would require the export of natural gas from either Israel or Cyprus to other countries in the region, such as Egypt and Jordan. These agreements are subject to a variety of risks, including geopolitical, regulatory, financial and other uncertainties. War, political violence, civil unrest or lack of intergovernmental cooperation could affect both our and our counterparties’ abilities to cooperate and to perform under these agreements, and could potentially lead to a breach or termination of such agreements. In addition, economic conditions or financial duress of our counterparties could jeopardize their ability to fulfill their payment obligations under these contracts. Furthermore, if material disruptions occur, including events or circumstances constituting force majeure under contract provisions, such that they inhibit us or our counterparties from performing under these GSPAs, or our counterparties are unable to pay us for a sustained period of time, we could incur a significant financial losses.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, they becomeit is becoming more dependent on us and our partners for theirits source of natural gas supply. Any material disruption in our ability to deliver natural gas to the State of Israel could have a material impact on our expected profitability, financial performance and reputation.
We are subject to certain regulatory provisions under the Framework, as adopted by the Government of Israel, including a requirement to reduce our ownership in the Tamar and Dalit fields to 25% by the end of 2021. We recently signed a definitive agreement to divest a 7.5% working interest in each of the fields to Tamar Petroleum Ltd., closing of the transaction is subject to satisfactory conclusion of certain conditions, including Tamar Petroleum's debt financing. Upon closing, we will receive consideration of both cash and Tamar Petroleum Ltd. shares, approximating 70% and 30%, respectively, of the transaction value, which will fluctuate based on market conditions. In accordance with the Framework, we must divest Tamar Petroleum Ltd. shares received by the end of 2021. In addition, changes in Israel's fiscal and/or regulatory regimes or energy policies occurring as a result of government policy on natural gas development and/or exports could delay or reduce the profitability of our Tamar and/or Leviathan development projects, and/or render future exploration and development projects uneconomic.
Development of our Eastern Mediterranean natural gas assets requires substantial investment and will take several years to complete. Our partners must be able to fund their share of investment costs through the development cycle, through cash flow from operations, external credit facilities, or other sources, including financing arrangements. If our project partners' cash flows or ability to maintain adequate financing are negatively impacted through similar risks factors described herein, the development of a project could be delayed and the timing and receipt of planned cash flows and expected profitability could be negatively impacted.
Due to the scale of our Leviathan (Israel) and Aphrodite (Cyprus) discoveries, realization of their full economic value depends on our ability to execute successful phased, development scenarios, the failure or delay of which could reduce our future growth and have negative effects on our future operating results. Offshore projects of this magnitude entail significant technical complexities including subsea tiebacks to a FPSO or production platform, pressure maintenance systems, gas re-injection systems, onshore receiving terminals, or other specialized infrastructure. In addition, we depend on third-party technology and service providers and other supply chain participants for these complex projects. Delays and differences between estimated and actual timing of critical events related to these projects could have a material adverse effect on our results of operations.
Concentration of capital in, and production and cash flows from, certain operations may increase our exposure to risks enumerated herein.
A significant portion of our production and revenues is highly concentrated and is generated from a limited number of conventional deepwater wells. These wells, located in the Gulf of Mexico, offshore Israel and offshore Equatorial Guinea, contributed approximately 33% of our 2017 total consolidated revenues and 34% of our 2017 total consolidated sales volumes. In addition, with the recording of reserves associated with the initial development of the Leviathan field, we now have a major concentration of reserves offshore Israel, with approximately 47% of our year-end 2017 proved reserves attributable to this area. These fields are also capital and resource-intensive.
Although we carry contingent business interruption for these producing assets, as well as other insurance, the insurance may be insufficient to cover all of risks including, a disruption to downstream operations impacting the processing, marketing and distribution of our production, such as from an accident, natural disaster, government intervention or other event, would have a significant impact on our production profile, cash flows, profitability, and overall business plan.
We also have significant concentrations of capital and production in unconventional basins including the DJ Basin, Delaware Basin and Eagle Ford Shale, and we expect to invest approximately 65%, of our total capital investment program to development activities in these areas in 2018. Restrictions in land access, rapid changes in drilling and completion technology, significant increases in drilling and completion costs, lack of availability of downstream services, changes in regulations and other risks impacting these areas, as enumerated in certain risk factors described herein, can have immediate, significant negative impacts on our production, cash flows, profitability and financial position.
A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss.
We dependare 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 vendors,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 has increased. A cyber attack could include gaining unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites. SCADA-basedSupervisory 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, could disrupt 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 failure to reach the intended target or a drilling incident;
data corruption or operational disruption of production infrastructure could result in loss of production, or accidental discharge;
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 on a third-party gathering or pipeline service provider could prevent us from marketing our production, resulting in a loss of revenues;
a cyber attack involving commodities exchanges or financial institutions could slow or halt commodities trading, thus preventing us from marketing our production or engaging in hedging activities, resulting in a loss of revenues;
a cyber attack which halts activities at a power generation facility or refinery using natural gas as feed stock could have a significant impact on the natural gas market, resulting in reduced demand for our production, lower natural gas prices, and reduced revenues;
a cyber attack on a communications network or power grid could cause operational disruption resulting in loss of revenues;
a deliberate corruption of our financial or operational data, or data theft, could result in events of non-compliance which could lead to regulatory fines or penalties; 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 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 increasing governmental regulations and environmental 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, reduced ability to obtain new leases, or loss of 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 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
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 impacts 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 factors 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 violent acts such as from civil disturbances, terrorist acts, regime changes cross-border violence, war, piracy, or other conflicts that may occur in regions that encompass our operations.
Certain regions, such as the Middle East and Africa, continue to experience varying degrees of political instability, public protests and terrorist attacks. We operate in regions of the world that have experienced such incidents or are in close proximity to areas where violence has occurred. Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as military or other actions taken in response to these acts, could cause instability in the global financialfiscal regimes and energy markets. Continued or escalated civilrelated government policies, tax laws and political unrest and acts of terrorismregulations in the regions in which we operate could result in curtailment of our operations. In the event that regions in which we operate experience civil or political unrest or acts of terrorism, especially in areas where such unrest leads to regime change, our operations in such regions could be materially impaired.
We monitor the economicUS and political environments of theother countries in which we operate. However, we are unable
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 predict the occurrencefiscal regimes or energy policies of disturbancesthese 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, making sweeping modifications to the Internal Revenue Code including a lower corporate tax rate, changes to credits and deductions, and a move to a 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 those noted above. In addition, we have limited ability(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 mitigate their impact.
Civil disturbances, terrorist acts, regimewhether any such legislative changes war,will be proposed or conflicts,enacted in the future, or the threats thereof,timing of any such action. Further, we cannot predict how government agencies or courts will interpret existing regulations and tax laws, including 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 price in the following results,ways, among others:
increased volatilityrestrict resource access or investment in global crude oil, natural gas and NGL priceslease holdings;
limit or cancel exploration and/or development activities, which could negatively impact the global economy, resulting in slower economic growth rates, which could reduce demand for our products;
have a long-term negative impact on the globalquantities 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 supply if infrastructure or transportation are disrupted, leading to further commodity price volatility;natural gas.
difficultyA change in attractinginternational and/or US federal and retaining qualified personnel to work in areas with potential for conflict;
inability of our personnel or supplies to enter or exit the countries where we are conducting operations;
disruption ofstate climate policy could have a significant impact on our operations dueand profitability.
Domestic and international responses to evacuationclimate and related energy issues are matters of personnel;
inabilitypublic policy consideration. We are currently in a period of increasing uncertainty as to deliver our production duethese matters and, at this time, it is difficult 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 terminalsanticipate how the current US Administration, or other operating assets;
damageentities, 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 destruction of property belonging to our natural gas purchasers leading to interruption of natural gas deliveries, claims of force majeure, and/or termination of natural gas sales contracts, resulting in a reduction in our revenues;
inability of our servicestate laws and equipment providers to deliver items necessary for us to conduct our operations;
lack of availability of drilling rigs, oilfield equipment or services if third party providers decide to exit the region;
shutdown of a financial system, communications network, or power grid causing a disruption to our business activities; and
capital market reassessment of risk and reduction of available capital making it more difficult for us and our partners to obtain financing for potential development projects.
Loss of property and/or interruption of our business plans resulting from civil unrestregulations regarding climate policy could have a significant negative impact on our earningsability to explore for and cash flow.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 states in the US have taken measures to reduce emissions of greenhouse gases primarily through the development of greenhouse gas emission inventories and/or regional greenhouse gas cap-and-trade programs. For a description of existing and proposed greenhouse gas rules and regulations, see Items 1. and 2. Business and Properties – Regulations. 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 that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, 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 us to comply with a number of US and international laws and regulations, violations of which could result in substantial fines or sanctions and/or impair our ability to do business.
Our operations require us to comply with complex and frequently-changing US and international laws and regulations, such as those involving anti-corruption, competition and antitrust, anti-boycott, anti-money laundering, import-exportcontrol, 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 notresult in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. See We are subject to increasing governmental regulations and environmental
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.
While hydraulic fracturing has been utilized in oil and gas development for decades, certain parties have enough insurancecalled for further study of the technique's alleged environmental and health effects, for additional regulation of the technique and, in some cases, for a moratorium or ban on the use of hydraulic fracturing. Because of elevated public sensitivity around the topic, federal, state and local governments are continually conducting studies, evaluating their regulatory programs and considering additional requirements on and regulation of hydraulic fracturing practices. At the national level, proposals have been introduced from time to cover any losstime in the US Congress that, if implemented, would subject hydraulic fracturing to further regulation, thereby limiting its use or increasing its cost.
Federal agencies addressing hydraulic fracturing under existing authorities include the EPA and the BLM, under the US Department of propertythe 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, 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 claims resulting from these risks.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 crude oil and natural gas operations are subject to hazards and risks inherent in the drilling, production and transportation of crude oil, NGLs and natural gas, and NGLs, including:
pipeline ruptures and spills;
fires, explosions, blowouts and well cratering;
equipment malfunctions and/or mechanical failure on high-volume, high-impact wells;
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, NGL and natural gas and NGL operations;
leaks or spills occurring during the transfer of hydrocarbons from an FPSO to an oil tanker;
loss of product occurring as a result of transfer to a truck or rail car or train derailments;
leakage or loss of access to hydrocarbons resulting from formations with abnormal pressures and basin subsidence which could result in leakage or loss of access to hydrocarbons;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.
Any of these risks or hazards can result in injuries and/or deaths of employees, supplier personnel or other individuals, loss of hydrocarbons, environmental pollution and other damage to our properties or the properties of others, regulatory investigations and administrative, civil and criminal penalties or restricted access to our properties.
In addition, our operations and financial results could be significantly impacted by adverse weather conditions and natural disasters in the areas we operate including:
hurricanes, tropical storms, cyclones, windstorms, or “superstorms”“superstorms,” which could affect our operations in areas such as Texas and the Gulf of Mexico;Texas;
winter storms and snow, which could affect our operations in the DJ Basin;
extremely high temperatures, which could affect third partyour midstream or third-party gathering and processing facilities in the DJ Basin and Texas;
severe droughts, resultingwhich could result in new restrictions on water usage in the DJ Basin and Texas;
harsh weather and rough seas offshore certain international locations, which could limit exploration activities; and
other natural disasters.
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, ormay result in noncommercial quantities of hydrocarbons.hydrocarbons or may be less productive than our initial estimates.
We are planningexpect to invest significant amounts of capital to continue development of our US onshore unconventional resources as well asand 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 new technologies to drive capital and cost efficiencies in drilling and completion, as well as onand the availability of third party infrastructureand access to provide flow assurance and transportation of production to end markets.
Development of offshore resources is capital and resource-intensive and may require several years to complete. In order to timely advance significant offshore discoveries, we may progress multiple development concepts simultaneously, with the realization that only one concept may ultimately be approved or be economically feasible. This approach may result in our writing off costs related to certain development concepts that must be eliminated from further consideration once a final development option has been determined.
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, processingtransportation or transportation,processing, and production may be delayed until such infrastructure is constructed.
Exploratory drilling either within existing or new ventures in countries which have no history of hydrocarbon sector investment, subjects us to risks and may not result in the discovery of commercially productive reservoirs.
Exploratory drilling requires significant capital investment and does not always result in commercial quantities of hydrocarbons or new development projects. In addition, exploratory drilling activities may be curtailed, delayed or canceled, or development plans may change, resulting in significant exploration expense, as a result of a variety of factors, including unexpected drilling conditions and pressure or other irregularities in formations. Furthermore, remote locations may make it more difficult and time-consuming to transport personnel, equipment and supplies, and we may face more difficult environments, such as oil sands, deepwater, or ultra-deepwater, in our efforts to seek new reserves, and may need to develop or invest in new technologies. These operating environments, and potential for harsh weather, increase cost as well as drilling risk.
Exploratory dry holes can occur because seismic data and other technologies we use to determine potential exploratory drilling locations do not allow us to know conclusively prior to drilling a well that crude oil or natural gas is present or may be produced economically. In addition, a well may be successful in locating hydrocarbons, but we and our partners may decide not to develop the prospect due to other considerations.
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 or NGL production, and in certain cases, limited infrastructure. If commercial quantities of hydrocarbons are discovered, societiesareas with minimal or no current production must begin to address topics such topics 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, require usour Revolving Credit Facility (defined below), debt and equity issuances, and occasional sales of assets. Future cash flows from operations are subject to comply with a number of USvariables, as enumerated herein. If commodity prices decline for an extended period of time, we will evaluate our level of capital spending and international lawslikely reduce our investment program. As a result, we will have less ability to replace our reserves through drilling operations and regulations, violationsmay elect to forfeit our ownership interests or rights to participate in some properties, resulting in lower production over time as compared with prior years. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Operating Outlook – 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 could resultinclude the following:
a reduction 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-exportcontrol, marketing, environmental and/or taxation.
For example, the US Foreign Corrupt Practices Act (FCPA) and similar laws and regulations enacted or promulgated by countries pursuant to the 1997 Organisation for Economic Cooperation and Development Anti-Bribery Convention generally prohibit improper payments to foreign officials for the purposeslowing 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 explorationcustomer drilling and development activities, as well as plans on our dedicated acreage, which would directly and adversely impact demand for our midstream services;
the exportvolatility of crude oil, natural gas and liquidsNGL 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 over our customers’ business decisions and operations, 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.
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 leading to increased public scrutiny of injection safety.
The development of new environmental initiatives or regulations related to acquisition, withdrawal, storage and use of surface water or groundwater, or treatment and discharge of water waste, may limit our ability to use techniques such as hydraulic fracturing, increase our development and operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted and all of which could have an adverse effect on our operations and financial condition. See Items 1. and 2. Business and Properties – Hydraulic Fracturing. A negative shift in investor sentiment of the oil and gas industry could adversely affect our 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 stop financing oil and gas and related infrastructure projects.
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 global populism and general political uncertainty.
Following the 2008/2009 global financial crisis, the world has experienced lower economic growth versus the levels attained in previous decades. 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 regulated byattempting to focus the import/export lawspublic'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 and Russia, and/or among China, Russia 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 impacting 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 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, we had $6.6 billion of consolidated debt, of which $560 million relates to Noble Midstream Partners, and indebtedness represented 39% of our total book capitalization (sum of debt plus shareholders' equity).
Indebtedness affects our operations in several ways, including the following:
a portion of our cash flows from operating activities must be used to service our indebtedness and is not available for other countriespurposes;
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 operate. may be more vulnerable to general adverse economic and industry conditions.
We may incur additional debt in order to fund our exploration, development and acquisition activities. A higher level of indebtedness increases the risk that our financial flexibility may deteriorate. Our ability to meet our debt obligations and service
our debt depends on future performance. General economic conditions, commodity prices, and financial, business and other factors 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 US,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. 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. 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:
acquiring desirable producing properties or new leases for future exploration;
acquiring or increasing access to gathering, transportation and processing services and capacity;
marketing our crude oil, NGL and natural gas production;
acquiring the equipment and expertise necessary to operate and develop properties; and
attracting and retaining employees with certain items requiredskills.
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 crude oil, NGL and natural gas reserves are not precise.
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 12-month average commodity prices; therefore, reserves quantities will change when actual prices increase or decrease. As estimated production, development activitiesand abandonment costs are based on year-end economic conditions, reserves quantities will also change when these costs increase or decrease.
Reserves estimates depend on a number of factors and assumptions that may be considered “dual-use”, having both commercialvary considerably from actual results, including:
historical production from the area compared with production from other areas;
assumed effects of regulations by governmental agencies, including the SEC;
anticipated development cycle time;
future development costs;
future operating and military applicationsabandonment costs;
impacts of cost recovery provisions in contracts with foreign governments;
severance and therefore,excise taxes; and
workover and remedial costs.
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 specific importpositive or export restrictions. negative revisions, and actual production, revenues and expenditures with respect to our reserves likely will vary, possibly materially, from estimates. Any such negative revisions could result in an asset impairment charge.
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 government imposes economic and trade sanctions againstinternational 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 foreign countriesfiscal, antitrust and regimes. The sanctionsother 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 basedsubject 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, including claims of conflicts of interest, related to Noble Midstream Partners. Any liability resulting from such claims could have a material adverse effect on US foreign policyour future business, financial condition, results of operations and national security goalscash 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 change over time.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.
As a developer, owner and operator of crude oil and natural gas properties, we are subject to various laws and regulations relating to the discharge of materials into, and the protection of, the environment. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. See We are subject to increasing governmental regulations and environmental requirements that may cause us to incur substantial incremental costs, below, and Item 8. Financial Statements and Supplementary Data – Note 17. Commitments and Contingencies.Federal, state and local hydraulic fracturing and water disposal legislation and regulation could increase our costs or restrict our ability to produce crude oil, natural gas and NGLs economically and in commercial quantities.
While hydraulic fracturing has been utilized in oil and gas development for decades, certain parties have called for further study of the technique's alleged environmental and health effects, for additional regulation of the technique and, in some cases, for a moratorium or ban on the use of hydraulic fracturing. Because of elevated public sensitivity around the topic, federal, state and local governments are continually conducting studies, evaluating their regulatory programs and considering additional requirements on and regulation of hydraulic fracturing practices.
At the national level, proposals have been introduced from time to time in the US Congress that, if implemented, would subject hydraulic fracturing to further regulation, thereby limiting its use or increasing its cost.
Federal agencies addressing hydraulic fracturing under existing authorities include the EPA, which has issued technical reports and developed various rules and guidelines regarding hydraulic fracturing activities, and the BLM, under the US Department of the Interior, which has issued final rules impacting hydraulic fracturing on federal and Indian lands. Some of these rules are subject to pending challenges and, on March 28, 2017, an executive order was signed directing the EPA and the BLM to review their rules and, if appropriate, to initiate rulemaking to rescind or revise them consistent with the stated policy of promoting clean and safe development of the nation’s energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production. Accordingly, the EPA and the BLM have taken actions to delay or rescind certain requirements related to hydraulic fracturing activities. See Items 1. and 2. Business and Properties - Hydraulic Fracturing.Each of the states, as well as certain localities, where we operate have adopted or may adopt regulations on drilling activities in general or hydraulic fracturing in particular that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, a number of local communities in Colorado have attempted to increase regulatory requirements on crude oil and natural gas development. In addition, some state regulatory agencies have modified their regulations to account for potential induced seismicity with regard to the operation of injection wells used for waste disposal.
We are dependent on the use of hydraulic fracturing practices to produce commercial quantities of crude oil and natural gas, particularly from wells in our US onshore basins. Additional federal, state or local restrictions on hydraulic fracturing, water disposal or other drilling activities that may be imposed in areas where we conduct business, such as US onshore, could significantly increase our operating, capital and compliance costs as well as delay or halt our ability to develop crude oil, natural gas and NGL reserves. See Items 1. and 2. Business and Properties – Regulations and – Hydraulic Fracturing.The marketability of our production is dependent upon transportation and processing facilities over which we may have no direct control.
The marketability of our production from our US onshore areas and Gulf of Mexico depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems, rail service, and processing facilities. We deliver crude oil, natural gas and NGLs produced from these areas through gathering systems and pipelines, the majority of which we do not own.
In Israel, we rely on a state-owned pipeline and transportation system to deliver our production to customers and end users. Offshore Equatorial Guinea, our natural gas production is delivered to onshore processing and storage facilities operated by our partner, and the resulting products, as well as our crude oil production from Aseng and Alen, are lifted to tankers owned by third-parties.
Third-party systems and facilities may not be available to us in the future at a price that is acceptable to us. In addition, the lack of availability of, or capacity on, third-party systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Even where we have some contractual control over the transportation of our production through firm transportation arrangements, third-party systems and facilities may be temporarily unavailable due to market conditions or mechanical reliability or other reasons, including adverse weather conditions.
Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities, could delay or curtail production, thereby harming our business and, in turn, our results of operations, cash flows, and financial condition.
Our ability to produce crude oil, natural gas and NGLs economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.
Drilling and development activities require the use of water and results in the production of waste water. For example, the hydraulic fracturing process, which we employ to produce commercial quantities of crude oil, natural gas and NGLs from many reservoirs, requires the use and disposal of significant quantities of water. In certain regions, there may be insufficient local capacity to provide a source of water for drilling activities. In those cases, water must be obtained from other sources and transported to the drilling site, adding to the development cost. Waste water from oil and gas operations often is disposed of via underground injection. Some studies have linked earthquakes or induced seismicity in certain areas to underground injection, which is leading to increased public scrutiny of injection safety.
The development of new environmental initiatives or regulations related to acquisition, withdrawal, storage and use of surface water or groundwater, or treatment and discharge of water waste, may limit our ability to use techniques such as hydraulic fracturing, increase our development and operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial condition. See Items 1. and 2. Business and Properties – Hydraulic Fracturing.
Failure to adequately fund continued capital expenditures could adversely affect our properties.
Our exploration, development, and acquisition activities require capital expenditures to achieve production and cash flows. In particular, major offshore projects have a multi-year long development cycle time, which means that development spending occurs for several years before the project begins producing hydrocarbons and generating cash flows. As examples, assets and infrastructure for export of natural gas from Leviathan require a multi-billion dollar investment prior to production startup. Furthermore, while the majority of our assets are held by production, certain of our assets, such as our Eagle Ford Shale and Delaware Basin properties, are held through continuous development obligations. Therefore, we are contractually obligated to fund a level of development activity in these areas and failure to meet these obligations may result in the loss of a lease.
Historically, we have funded our capital expenditures through a combination of cash flows from operations, our unsecured revolving credit facility (Revolving Credit Facility), debt and equity issuances, and occasional sales of assets. Future cash flows from operations are subject to a number of variables, such as the level of production from existing wells, commodity prices, and our success in finding, developing and producing new reserves.
A negative shift in investor sentiment of the oil and gas industry could adversely affect our ability to raise equity and debt capital.
Certain segments of the investor community have recently developed negative sentiment towards investing in our industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. Some investors, including certain pension funds, university endowments and family foundations, have stated policies to disinvest in the oil and gas sector based on their social and environment considerations. Certain other stakeholders have also pressured commercial and investment banks to stop funding oil and gas projects.
Such developments could result in downward pressure on the stock prices of oil and gas companies, including ours. This may also potentially result in a reduction of available capital funding for potential development projects impacting our future financial results.
Indebtedness may limit our liquidity and financial flexibility.
At December 31, 2017, we had $6.8 billion of consolidated debt, and indebtedness represented 39% of our total book capitalization (sum of debt plus shareholders' equity).
Our indebtedness affects our operations in several ways, including the following:
a portion of our cash flows from operating activities must be used to service our indebtedness and is not available for other purposes;
we may be at a competitive disadvantage as compared to similar companies that have less debt;
a covenant contained in our Credit Agreement provides that our total debt to capitalization ratio (as defined in the Credit Agreement) will not exceed 65% at any time, which may make additional borrowings more expensive, thereby affecting our flexibility in planning for, and reacting to, changes in the economy and our industry;
additional future financing for working capital, capital expenditures, acquisitions, general corporate or other purposes may have higher costs and more restrictive covenants;
changes in our debt credit ratings may negatively affect the cost, terms, conditions and/or availability of future financing, and lower ratings will increase the interest rate and fees we pay on our Revolving Credit Facility; and
we may be more vulnerable to general adverse economic and industry conditions.
We may incur additional debt in order to fund our exploration, development and acquisition activities. A higher level of indebtedness increases the risk that our financial flexibility may deteriorate. Our ability to meet our debt obligations and service our debt depends on future performance. General economic conditions, commodity prices, and financial, business and other factors will affect our operations and our future performance. Many of these factors are beyond our control and we may not be able to generate sufficient cash flow to pay the interest on our debt, and future working capital, borrowings and equity financing may not be available to pay or refinance such debt. See Item 8. Financial Statements and Supplementary Data – Note 10. Long-Term Debt.
A downgrade or other negative action with respect to our credit rating could negatively impact our business and financial condition.
A downgrade or other negative rating action could affect our requirements to post collateral as financial assurance of performance under certain contractual arrangements, such as pipeline transportation contracts, crude oil and natural gas sales contracts, work commitments and certain abandonment obligations, and potentially subject us to additional bonding and other assurance requirements with respect to our Gulf of Mexico assets. A lowering of our credit rating may negatively affect the cost, terms, conditions and availability of future financing.
We face significant competition and many of our competitors have resources in excess of our available resources.
We operate in highly competitive areas of crude oil and natural gas exploration, development, acquisition and production. We face intense competition from:
large multi-national, integrated oil and gas companies;
state-controlled national oil companies;
US independent oil and gas companies;
US onshore midstream companies;
service companies engaging in exploration and production activities; and
private investing in oil and gas equity funds.
We face competition in a number of areas such as:
seeking to acquire desirable producing properties or new leases for future exploration;
acquiring or increasing access to gathering, processing and transportation services and capacity;
marketing our crude oil, natural gas and NGL production;
seeking to acquire the equipment and expertise necessary to operate and develop properties; and
attracting and retaining employees with certain skills.
Many of our competitors have financial and other resources substantially in excess of those available to us. Such companies may be able to pay more for seismic information and lease rights on crude oil and natural gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. This highly competitive environment could have an adverse impact on our business.
Estimates of crude oil, natural gas and NGL reserves are not precise.
Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, natural gas and NGLs that cannot be measured in an exact manner, and there are numerous uncertainties inherent in estimating reserves quantities and their value, including factors that are beyond our control.
In accordance with the SEC's rules for oil and gas reserves reporting, our reserves estimates are based on 12-month average commodity prices; therefore, reserves quantities will change when actual prices increase or decrease. As estimated production, development and abandonment costs are based on year-end economic conditions, reserves quantities will also change when these costs increase or decrease.
Reserves estimates depend on a number of factors and assumptions that may vary considerably from actual results, including:
historical production from the area compared with production from other areas;
the assumed effects of regulations by governmental agencies, including the SEC;
assumptions concerning future crude oil, natural gas, and NGL prices;
anticipated development cycle time;
future development costs;
future operating and abandonment costs;
impacts of cost recovery provisions in contracts with foreign governments;
severance and excise taxes; and
workover and remedial costs.
For these reasons, estimates of the economically recoverable quantities of crude oil, natural gas and NGLs attributable to any particular group of properties, classifications of those reserves based on risk of recovery, and estimates of the future net cash flows expected from them prepared by different petroleum engineers, or by the same petroleum engineers but at different times, may vary substantially. Estimation of crude oil, natural gas and NGL reserves in emerging areas or areas with limited historical production is inherently more difficult, and we may have less experience in such areas. Accordingly, reserves estimates may be subject to positive or negative revisions, and actual production, revenues and expenditures with respect to our reserves likely will vary, possibly materially, from estimates. Any such negative revisions could result in an asset impairment charge.
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, such as us, can be involved in various legal proceedings, such as title, royalty, or contractual disputes, in the ordinary course of business. For example, in certain states, oil and gas companies are often the target of “legacy lawsuits,” by which a landowner claims that oil and gas operations, often performed many years ago and by another operator, caused pollution or contamination of a property. Various properties we have owned over the past decades potentially expose us to “legacy lawsuit” claims. Similarly, neighboring landowners may allege that current operations cause contamination or create a nuisance.
Because we maintain a diversified portfolio of assets that includes both US and international projects, the complexity and types of legal procedures with which we may become involved may vary, and we could incur significant legal and support expenses in different jurisdictions. For instance, we historically have had to address certain fiscal, antitrust and other regulatory challenges in Israel, including a current class action lawsuit filed by petitioners alleging we and our partners in Tamar violated antitrust laws through the monopolistic pricing of natural gas to the citizens of Israel. Legal proceedings such as this could result in a substantial liability and/or negative publicity about us and adversely affect the price of our common stock. In addition, legal proceedings distract management and other personnel from their primary responsibilities.These proceedings are subject to the uncertainties inherent in any litigation. We will defend ourselves vigorously in all such matters. However, if we are not able to successfully defend ourselves, there could be a delay or even halt in our exploration, development or production activities or other business plans, resulting in a reduction in reserves, loss of production and reduced cash flows.
One of our subsidiaries acts as the general partner of a publicly traded master limited partnership, Noble Midstream Partners, which may involve a greater exposure to legal liability than our historic business operations.
One of our subsidiaries acts as the general partner of Noble Midstream Partners, a publicly traded master limited partnership. Our control of the general partner of Noble Midstream Partners may increase the possibility that we could be subject to claims of breach of fiduciary duties, including claims of conflicts of interest, related to Noble Midstream Partners. Any liability resulting from such claims could have a material adverse effect on our future business, financial condition, results of operations and cash flows.
We may be subject to risks in connection with acquisition and divestiture activities.
As part of our business strategy, we have made, and will likely continue to make, acquisitions of oil and gas properties and/or entities that own them. Furthermore, if we are unable to make attractive acquisitions, our future growth could be limited. Moreover, even if we do make acquisitions, they may not result in an increase in our cash flows from operations or otherwise result in the benefits anticipated due to various risks, including, but not limited to:
incorrect estimates or assumptions about reserves, exploration potential or potential drilling locations;
incorrect assumptions regarding future revenues, including future commodity prices and differentials, or regarding future development and operating costs;
incorrect assumptions regarding potential synergies and the overall costs of equity or debt;
difficulties in integrating the operations, technologies, products and personnel of the acquired assets or business; and
unknown and unforeseen liabilities or other issues related to any acquisition for which contractual protections prove inadequate, including environmental liabilities and title defects.
The acquisition of a property or business requires management to make complex judgments and assessments, and the accuracy of the assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties
that we believe to be consistent with industry practices. Our review will not reveal all existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities.
We also maintain an ongoing portfolio management program to ensure our company is well-positioned with assets that offer growth at financially attractive investment options. Therefore, we may periodically divest certain material assets which may help to generate organizational and operational efficiencies as well as cash for use in our capital investment program or to repay outstanding debt.
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. An uneconomic or unsuccessful acquisition or divestiture effort may divert management’s attention and our financial resources away from existing operations, which could have a material adverse effect on our financial condition and results of operations.
We are exposed to counterparty credit risk as a result of our receivables, hedging transactions and cash investments.
We are exposed to risk of financial loss from joint venture and other receivables. We are the operator on a majority of our joint venture development projects, including Leviathan. As operator of the joint ventures,venture operator, we pay joint venture expenses and make cash calls on our nonoperating partners for their respective shares of joint venture costs. These projects are capital cost intensive and, in some cases, a nonoperating partner may experience a delay in obtaining financing for its share of the joint venture costs or have liquidity problems resulting in slow payment of joint venture costs that can result in potential delays in our development projects.
In addition, some of our joint venture partners are not as creditworthy as we are and may experience credit rating downgrades or liquidity problems that may hinder their ability to obtain financing. Counterparty liquidity problems could result in a delay in our receiving proceeds from reimbursement of joint venture costs. Nonperformance by a joint venture partner could result in significant financial losses.
Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. During periods of falling commodity prices, our commodity derivative receivable positions increase, which increases our counterparty credit exposure. We also had approximately $675 million inhave cash and cash equivalents at December 31, 2017 deposited with financial institutions, a majority of which wasis 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 thejoint venture partners, purchasers, banks and financial institutions with which we invest and engage in hedging transactions, and maintain credit insurance,conduct business, we are unable to predict sudden changes in solvency of the financial institutionsthese counterparties and may be exposed to associated risks.
If one or more of our joint venture partners, hedge counterparties and financial institutions were to experience a sudden deterioration in liquidity, it could impair their ability to perform under the terms of our contracts. We are unable to predict sudden changes in creditworthiness or ability of these parties to perform and could incur significant financial losses.
Credit enhancements have been obtained from some parties in the form of parental guarantees, letters of credit or credit insurance; however, not all of our counterparty credit is protected through guarantees or credit support. In addition, we maintain credit insurance associated with specific purchasers. However, nonperformance by a hedge counterparty or financial institution could result in significant financial losses.
Commodity hedging transactions may limit our potential gains or fail to protect us from declines in commodity prices.prices.
In order to reduce the impact of commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas, we enter into hedging arrangements with respect to a portion of our expected revenues. Our hedges, consisting of a series of derivative instrument contracts, are limited in duration, usually for periods of one to three years. While intended to reduce the effects of volatile crude oil and natural gas prices, such transactions may limit our potential gains if prices rise over the price established by the arrangements. Conversely, our hedging program may be inadequate to protect us from continuing and prolonged declines in the price of crude oil or natural gas.
Global commodity prices are volatile. Such volatility challenges our ability to forecast and, as a result, it may become more difficult to manage our hedging program. In trying to manage our exposure to commodity price risk, we may end up hedging too much or too little, depending upon how our crude oil or natural gas volumes and our production mix fluctuate in the future. Hedging transactions may also expose us to the risk of financial loss in certain circumstances, including instances in which: our production is less than expected; there is a widening of price basis differentials between delivery points for our production and
the delivery points assumed in the hedge arrangement; the counterparties to our futures contracts fail to perform under the contracts; or a sudden unexpected event materially impacts crude oil or natural gas prices. See Item 8. Financial Statements and Supplementary Data – Note 8.13. Derivative Instruments and Hedging Activities.The insurance we carry is insufficient to cover all of the risks we face, which could result in significant financial exposure.
Exploration for and production of crude oil and natural gas can be hazardous, involving natural disasters or other catastrophic events such as hurricanes, earthquakes, blowouts, well cratering, fire and explosion, loss of well control, pipeline disruptions, mishandling of fluids and chemicals, and possible underground migration of hydrocarbons and chemicals, any of which can result in damage to or destruction of wells or formations or production facilities, injury to persons, loss of life, or damage to property and the environment. Exploration and production activities are also subject to risk from political developmentsother 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 future availability and cost of insurance to be impacted by events such events as hurricanes, earthquakes tsunami and other natural disasters. Impacts could include tighter underwriting standards;standards, limitations on scope and amount of coverage;coverage, and higher premiums, and will depend, in part, on future changes in laws and regulations regarding exploration and production activities in the Gulf of Mexico and other areas in which we operate, including possible increases in liability caps for claims of damages from oil spills. We will continue to monitor for any legislative or regulatory changes related to offshore exploration and production and its potential impact on the insurance market and our overall risk profile, and adjust our risk and insurance program to provide protection, at a level that we can afford considering the cost of insurance and our desired rates of return, against disruption to our operations and cash flows.
If an event, for example, a major offshore incident resulting in significant personal injury and/or environmental and physical damage, occurs that is not covered by insurance or not fully protected by insured limits, it could have a significant adverse impact on our financial condition, results of operations and cash flows. See Items 1. and 2. Business and Properties – Risk and Insurance Program, above. Provisions in our Certificate of Incorporation and Delaware law may inhibit a takeover of us.
Under our Certificate of Incorporation, our Board of Directors is authorized to issue shares of our common or preferred stock without approval of our shareholders. Issuance of these shares could make it more difficult to acquire us without the approval of our Board of Directors as more shares would have to be acquired to gain control. In addition, Delaware law imposes restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock. These provisions may deter hostile takeover attempts that could result in an acquisition of us that would have been financially beneficial to our shareholders. .
Item1B. Unresolved Staff Comments
None.
Item 3. Legal Proceedings
We are involved in various legal proceedings in the ordinary course of business. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters and we believe that the ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations or cash flows. For discussion of material legal proceedings, see See Item 8. Financial Statements and Supplementary Data – Note 17.11. Commitments and Contingencies. 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 Our common stock, $0.01 par value, is listed and traded on the NYSE under the symbol “NBL.” The declaration and payment of dividends will beare 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.
Stock Prices and Dividends by QuartersThe high and low sales price per share of our common stock on the NYSE and quarterly dividends paid per share were as follows:
|
| | | | | | | | | | | | |
| | | High | | Low | | Dividends Per Share |
| 2016 | | | | | | |
| First Quarter | | $ | 35.04 |
| | $ | 23.77 |
| | $ | 0.10 |
|
| Second Quarter | | 38.62 |
| | 29.47 |
| | 0.10 |
|
| Third Quarter | | 37.50 |
| | 32.71 |
| | 0.10 |
|
| Fourth Quarter | | 42.03 |
| | 33.75 |
| | 0.10 |
|
| 2017 | | | | | | |
| First Quarter | | $ | 40.89 |
| | $ | 32.33 |
| | $ | 0.10 |
|
| Second Quarter | | 35.74 |
| | 27.66 |
| | 0.10 |
|
| Third Quarter | | 30.06 |
| | 22.99 |
|
| 0.10 |
|
| Fourth Quarter | | 29.58 |
| | 22.99 |
| | 0.10 |
|
On January 30, 2018,29, 2019, our Board of Directors declared a quarterly cash dividend of $0.10$0.11 per common share. The dividend will be paid February 26, 2018,25, 2019, to shareholders of record on February 12, 2018. The amount11, 2019. See Item 8. Financial Statements and Supplementary Data – Consolidated Statements of future dividends will be determined on a quarterly basis at the discretion of our Board of Directors and will depend on earnings, financial condition, capital requirements and other factors.Shareholders' Equity. Transfer Agent and Registrar The transfer agent and registrar for our common stock is Wells Fargo Bank,Computershare Trust Company N.A., 1110 Centre Pointe Curve, Suite 101 Mendota Heights, MN 55120.250 Royall Street, Canton, MA, 02021.
Stockholders’Shareholders’ Profile Pursuant to the records of the transfer agent, as of February 9, 2018,7, 2019, the number of holders of record of our common stock was 561.541.
Stock Repurchases The following table summarizes repurchases of our common stock occurring in fourth quarter 2017:
|
| | | | | | | | | | | | | |
| 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 | | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs |
| | | | | | | | | (in thousands) |
| 10/1/2017 - 10/31/2017 | | 390 |
| | $ | 28.33 |
| | — |
| | — |
|
| 11/1/2017 - 11/30/2017 | | 85 |
| | 28.30 |
| | — |
| | — |
|
| 12/1/2017 - 12/31/2017 | | 20,173 |
| | 25.68 |
| | — |
| | — |
|
| Total | | 20,648 |
| | $ | 25.74 |
| | — |
| | — |
|
|
| | | | | | | | | | | | | | |
| 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 |
|
(1) Stock 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 restrictedcommon stock issued under our 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.
Stock Performance Graph This graph shows our cumulative total shareholder return over the five-year period from December 31, 20122013 to December 31, 2017.2018. The graph also shows the cumulative total returns for the same five-year period of the S&P 500 Index and a peer group of companies. The cumulative total return of the common stock of our peer group of companies includes the cumulative total return of our common stock.
Our peer group includes a broad group of US onshore and global exploration and production companies which are further diversified by location and number of resource plays as well as level of integration within the crude oil and natural gas business cycle. Our peer group consists of the following:
|
| | |
| Anadarko Petroleum Corp. | Hess Corp. |
Apache Corp. | Marathon Oil Corp. |
Cabot Oil & Gas Corp. | Murphy Oil Corp. |
ChesapeakeDevon Energy Corp. | Noble Energy, Inc. |
ContinentalApache Corp. | EOG Resources, Inc. | Pioneer Natural Resources Co. |
Devon EnergyCabot Oil & Gas Corp. | Hess Corp. | Range Resources Corp. |
EOG Resources, Inc.Chesapeake Energy Corp. | Marathon Oil Corp. | Southwestern Energy Co. |
| Continental Resources, Inc. | Murphy Oil Corp. | |
The comparison assumes $100 was invested on December 31, 20122013 in our common stock, in the S&P 500 Index and in our peer group of companies and assumes that all of the dividends were reinvested. In addition, the peer group investment is weighted based upon the market capitalization of each individual company within the peer group.
| | | Year Ended December 31, | 2013 | 2014 | 2015 | 2016 | 2017 | 2014 | 2015 | 2016 | 2017 | 2018 |
| Noble Energy, Inc. | $ | 135.07 |
| $ | 95.06 |
| $ | 67.16 |
| $ | 78.54 |
| $ | 60.93 |
| $ | 70.38 |
| $ | 49.73 |
| $ | 58.15 |
| $ | 45.11 |
| $ | 29.47 |
|
| S&P 500 | 132.39 |
| 150.51 |
| 152.59 |
| 170.84 |
| 208.14 |
| 113.69 |
| 115.26 |
| 129.05 |
| 157.22 |
| 150.33 |
|
| Peer Group | 131.72 |
| 113.35 |
| 70.13 |
| 101.33 |
| 90.55 |
| 86.06 |
| 53.24 |
| 76.93 |
| 68.75 |
| 51.93 |
|
Equity Compensation Plan Information The information required by this item is incorporated herein by reference to the 2018 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2017.
Item 6. Selected Financial Data | | | | | Year Ended December 31, | | Year Ended December 31, |
| (millions, except as noted) | | 2017 | | 2016 | | 2015 | | 2014 | | 2013 | | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
| Revenues and Income | | | | | | | | | | | | | | | | | | | | |
| Total Revenues | | $ | 4,256 |
| | $ | 3,491 |
| | $ | 3,183 |
| | $ | 5,115 |
| | $ | 5,015 |
| | $ | 4,986 |
| | $ | 4,256 |
| | $ | 3,491 |
| | $ | 3,183 |
| | $ | 5,115 |
|
| (Loss) Income from Continuing Operations Including Noncontrolling Interests | | (1,050 | ) | | (985 | ) | | (2,441 | ) | | 1,214 |
| | 907 |
| |
| Net (Loss) Income Including Noncontrolling Interests | | (1,050 | ) | | (985 | ) | | (2,441 | ) | | 1,214 |
| | 978 |
| |
| Net (Loss) Income Attributable to Noble Energy | | (1,118 | ) | | (998 | ) | | (2,441 | ) | | 1,214 |
| | 978 |
| |
| 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 |
|
| Per Share Data, Attributable to Noble Energy | | | | |
| | | | |
| | |
| | | | |
| | | | |
| | |
|
| (Loss) Earnings Per Share - Basic | | | | |
| | |
| | |
| | |
| | (0.14 | ) | | (2.38 | ) | | (2.32 | ) | | (6.07 | ) | | 3.36 |
|
| (Loss) Income from Continuing Operations | | $ | (2.38 | ) | | $ | (2.32 | ) | | $ | (6.07 | ) | | $ | 3.36 |
| | $ | 2.53 |
| |
| (Loss) Earnings Per Share - Basic | | (2.38 | ) | | (2.32 | ) | | (6.07 | ) | | 3.36 |
| | 2.72 |
| |
| (Loss) Earnings Per Share - Diluted | | | | | | | | | | | |
| (Loss) Income from Continuing Operations | | (2.38 | ) | | (2.32 | ) | | (6.07 | ) | | 3.27 |
| | 2.50 |
| |
| (Loss) Earnings Per Share - Diluted | | (2.38 | ) | | (2.32 | ) | | (6.07 | ) | | 3.27 |
| | 2.69 |
| | (0.14 | ) | | (2.38 | ) | | (2.32 | ) | | (6.07 | ) | | 3.27 |
|
| Cash Dividends Per Share | | 0.40 |
| | 0.40 |
| | 0.72 |
| | 0.68 |
| | 0.55 |
| | 0.43 |
| | 0.40 |
| | 0.40 |
| | 0.72 |
| | 0.68 |
|
| Year-End Stock Price Per Share | | 29.14 |
| | 38.06 |
| | 32.93 |
| | 47.43 |
| | 68.11 |
| | 18.76 |
| | 29.14 |
| | 38.06 |
| | 32.93 |
| | 47.43 |
|
| Weighted Average Shares Outstanding | | | | |
| | |
| | |
| | |
| |
| Weighted Average Number of Shares Outstanding | | | | | |
| | |
| | |
| | |
|
| Basic | | 469 |
| | 430 |
| | 402 |
| | 361 |
| | 359 |
| | 483 |
| | 469 |
| | 430 |
| | 402 |
| | 361 |
|
| Diluted | | 469 |
| | 430 |
| | 402 |
| | 367 |
| | 363 |
| | 483 |
| | 469 |
| | 430 |
| | 402 |
| | 367 |
|
| Cash Flows | | | | |
| | |
| | |
| | |
| | | | |
| | |
| | |
| | |
|
| Net Cash Provided by Operating Activities | | $ | 1,951 |
| | $ | 1,351 |
| | $ | 2,062 |
| | $ | 3,506 |
| | $ | 2,937 |
| | $ | 2,336 |
| | $ | 1,951 |
| | $ | 1,351 |
| | $ | 2,062 |
| | $ | 3,506 |
|
| Additions to Property, Plant and Equipment | | 2,649 |
| | 1,541 |
| | 2,979 |
| | 4,871 |
| | 3,947 |
| | 3,279 |
| | 2,649 |
| | 1,541 |
| | 2,979 |
| | 4,871 |
|
Proceeds from Divestitures (1) | | 2,073 |
| | 1,241 |
| | 151 |
| | 321 |
| | 327 |
| | 1,999 |
| | 2,073 |
| | 1,241 |
| | 151 |
| | 321 |
|
| 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 |
| | — |
| | — |
| | — |
| | — |
| | 312 |
| | 299 |
| | — |
| | — |
|
| Financial Position | | | | |
| | |
| | |
| | |
| | | | | | | | | | |
| Cash and Cash Equivalents | | $ | 675 |
| | $ | 1,180 |
| | $ | 1,028 |
| | $ | 1,183 |
| | $ | 1,117 |
| | $ | 716 |
| | $ | 675 |
| | $ | 1,180 |
| | $ | 1,028 |
| | $ | 1,183 |
|
| Property, Plant, and Equipment, Net | | 17,502 |
| | 18,548 |
| | 21,300 |
| | 18,143 |
| | 15,725 |
| |
| Property, Plant and Equipment, Net | | | 18,419 |
| | 17,502 |
| | 18,548 |
| | 21,300 |
| | 18,143 |
|
Goodwill (2) | | 1,310 |
| | — |
| | — |
| | 620 |
| | 627 |
| | 110 |
| | 1,310 |
| | — |
| | — |
| | 620 |
|
| Total Assets | | 21,476 |
| | 21,011 |
| | 24,196 |
| | 22,518 |
| | 19,642 |
| | 21,010 |
| | 21,476 |
| | 21,011 |
| | 24,196 |
| | 22,518 |
|
| Long-term Obligations | | | | |
| | |
| | |
| | |
| | | | | | | | | | |
| Long-Term Debt | | 6,746 |
| | 7,011 |
| | 7,976 |
| | 6,068 |
| | 4,566 |
| | 6,574 |
| | 6,746 |
| | 7,011 |
| | 7,976 |
| | 6,068 |
|
| Deferred Income Taxes | | 1,127 |
| | 1,819 |
| | 2,826 |
| | 2,516 |
| | 2,441 |
| | 1,061 |
| | 1,127 |
| | 1,819 |
| | 2,826 |
| | 2,516 |
|
| Asset Retirement Obligations, Noncurrent | | 824 |
| | 775 |
| | 861 |
| | 670 |
| | 547 |
| | 762 |
| | 824 |
| | 775 |
| | 861 |
| | 670 |
|
| Other | | 421 |
| | 328 |
| | 358 |
| | 417 |
| | 562 |
| | 403 |
| | 421 |
| | 328 |
| | 358 |
| | 417 |
|
| Total Equity | | 10,619 |
| | 9,600 |
| | 10,370 |
| | 10,325 |
| | 9,184 |
| | 10,484 |
| | 10,619 |
| | 9,600 |
| | 10,370 |
| | 10,325 |
|
| |
(1) | Proceeds for 2017 relate to the Marcellus Shale upstream divestiture and proceeds received from other transactions. Proceeds for 2016 primarily relate to US onshore non-strategic asset divestiture activity and the sell-down of Tamar interest. See Item 8. Financial Statements and Supplementary Data – Note 4.5. Acquisitions Divestitures and MergerDivestitures. |
| |
(2) | Goodwill at December 31, 2017 related to the Clayton Williams Energy Acquisition. Our previous goodwill balance was fully impaired at December 31, 2015. See Item 8. Financial Statements and Supplementary Data – Note 1. Summary of Significant Accounting Policies6. Goodwill Impairment. |
| | | | | Year Ended December 31, | | Year Ended December 31, |
| | | 2017 | | 2016 | | 2015 | | 2014 | | 2013 | | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
| Operations Information - Consolidated Operations | | | | |
| | |
| | |
| | |
| | | | |
| | |
| | |
| | |
|
| Consolidated Crude Oil Sales (MBbl/d) | | 129 |
| | 125 |
| | 112 |
| | 103 |
| | 99 |
| | 130 |
| | 129 |
| | 125 |
| | 112 |
| | 103 |
|
| Average Realized Price ($/Bbl) | | $ | 49.73 |
| | $ | 40.39 |
| | $ | 45.00 |
| | $ | 91.58 |
| | $ | 100.29 |
| | $ | 62.01 |
| | $ | 49.73 |
| | $ | 40.39 |
| | $ | 45.00 |
| | $ | 91.58 |
|
| Consolidated NGL Sales (MBbl/d) | | 58 |
| | 54 |
| | 39 |
| | 23 |
| | 16 |
| | 62 |
| | 58 |
| | 54 |
| | 39 |
| | 23 |
|
| Average Realized Price ($/Bbl) | | $ | 23.40 |
| | $ | 14.92 |
| | $ | 13.91 |
| | $ | 33.75 |
| | $ | 35.53 |
| | $ | 25.88 |
| | $ | 23.40 |
| | $ | 14.92 |
| �� | $ | 13.91 |
| | $ | 33.75 |
|
| Consolidated Natural Gas Sales (MMcf/d) | | 1,118 |
| | 1,397 |
| | 1,187 |
| | 992 |
| | 901 |
| | 922 |
| | 1,118 |
| | 1,397 |
| | 1,187 |
| | 992 |
|
| Average Realized Price ($/Mcf) | | $ | 3.01 |
| | $ | 2.42 |
| | $ | 2.44 |
| | $ | 3.38 |
| | $ | 2.97 |
| | $ | 2.76 |
| | $ | 3.01 |
| | $ | 2.42 |
| | $ | 2.44 |
| | $ | 3.38 |
|
| Proved Reserves | | | | |
| | |
| | |
| | |
| | | | |
| | |
| | |
| | |
|
| Crude Oil and Condensate Reserves (MMBbls) | | 457 |
| | 333 |
| | 307 |
| | 304 |
| | 322 |
| | 457 |
| | 457 |
| | 333 |
| | 307 |
| | 304 |
|
| NGL Reserves (MMBbls) | | 229 |
| | 219 |
| | 189 |
| | 128 |
| | 113 |
| | 266 |
| | 229 |
| | 219 |
| | 189 |
| | 128 |
|
| Natural Gas Reserves (Bcf) | | 7,680 |
| | 5,308 |
| | 5,549 |
| | 5,833 |
| | 5,828 |
| | 7,231 |
| | 7,680 |
| | 5,308 |
| | 5,549 |
| | 5,833 |
|
| Total Reserves (MMBoe) | | 1,965 |
| | 1,437 |
| | 1,421 |
| | 1,404 |
| | 1,406 |
| | 1,929 |
| | 1,965 |
| | 1,437 |
| | 1,421 |
| | 1,404 |
|
| Number of Employees | | 2,277 |
| | 2,274 |
| | 2,395 |
| | 2,735 |
| | 2,527 |
| | 2,330 |
| | 2,277 |
| | 2,274 |
| | 2,395 |
| | 2,735 |
|
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 (see(metrics should be reviewed in the context of additional information provided in the links below for further information)below)
EXECUTIVE OVERVIEW
Industry Outlook
Crude OilThe global oil and gas industry is cyclical, and crude oil prices are volatile, driven by crude oil supply, which includes OPEC and non-OPEC producers, and global crude oil demand.
In 2014, our industry entered a downturn due to oversupplied crude oil production from non-OPEC producers, primarily driven by US unconventional oil production growth from tight formations Building on the prior year's price recovery and the de-bottlenecking of transportation infrastructure. Coupled with OPEC’s decision not to reduce production quotas and muted global crude oilhigher demand, growth, crude oil prices began falling rapidly in late 2014.
The rapid decline intrended upward for most of 2018, with Brent and WTI crude oil prices impacted USreaching a four-year high, in excess of $80 and other non-OPEC producers' capital budgets, which resulted$70 per barrel, respectively. However, in lower crude oil production. Further, in late 2016, OPEC announced voluntary production curtailments in an effortNovember 2018, prices suddenly plunged, with Brent and WTI prices falling to stabilize excess crude oilnearly $50 and $40 per barrel, respectively, as traders focused on supply and crude oil prices and to rebalance crude oil inventories. The decline in supply from these producers has aided in stabilizing the crude oil market. As a result, crude oil prices have recently recovered to three-year record highs, while production from the US has increased, allowing US producers to absorbeconomics combined with concerns of slowing global market share.
Global crude oil products demand has increased, supported by lower crude oil prices and a synchronized global economic recovery, leading to increased refinery utilization and crude oil demand. Increased demand has further contributed to stabilizing crude oil prices.growth.
The outlook for 20182019 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. ReductionsEven if OPEC cuts production, US shale supply is expected to continue to grow due to capital investment in anticipation of the addition of takeaway capacity easing recent bottlenecks, such as in the Delaware Basin. These factors, and the potential for slower global growth and increasing global uncertainty, could suppress crude oil prices. In addition, the spread between WTI and Brent prices has been widening, resulting in comparatively lower prices for US production. However, reductions in industry investment, particularly for conventional crude oil development, will, over time, contribute to production declines, helping to balance supply and demand in the crude oil market.potentially supporting higher prices.
Natural Gas The US domestic natural gas market remains oversupplied as domestic production has continued to grow due to drilling efficiencies, completionhigher incremental volumes of DUC well inventoryassociated gas from oil wells and de-bottlenecking of transportation infrastructure. In contrast to crude oil supply curtailments, there has been little to offset natural gas supply growth, which continues to outpace demand domestically. As a result, natural gas prices remained range-bound in 2017. We expect this situation2018, with an expectation to continue into 2018,as such in 2019, with natural gas prices at or near current or recent trading levels.
Impact of Current Commodity PricesModest commodity price improvement has increased both our consolidated average realized crude oil and consolidated average natural gas prices by approximately 20% in 2017 as compared to 2016. The chart below shows the historical trend in benchmark prices for West Texas Intermediate (WTI)WTI crude oil, Brent crude oil and US Henry Hub natural gas.
BecauseDevelopment and Operating Costs As commodity prices strengthened, the global economic outlookdemand for oilfield equipment, services and infrastructure, particularly in US onshore basins, began to rise, 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. 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 recent crude oil price decline from mid-2018 highs, the development and operating cost structure has begun to shift downward, and we expect margin pressure will continue into 2019.
Takeaway Capacity With higher commodity price environmentprices and the resurgence of US onshore drilling activity, demand increased for access to gathering facilities, transportation and/or takeaway pipelines due to growing production volumes. In the Delaware Basin, midstream suppliers are uncertain,working to construct new gathering, transportation and processing facilities or to repurpose existing infrastructure in an effort to proactively outpace expected production growth. In this regard, we have maintainedsecured near-term flow assurance and long-term out-of-basin takeaway from the Delaware Basin 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 robust financial liquidity positionmajority 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.
Initiatives have been underway in the State of Colorado to regulate, limit or ban hydraulic fracturing or other facets of crude oil and natural gas exploration, development or operations for some time. We have also plannedare monitoring the work of the State of Colorado General Assembly 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, capital investment program that will be flexiblethe US Administration imposed import tariffs of 25% on steel products and responsive to positive 10% on aluminum products, as well as quantitative restrictions on imports of steel and/or negative price conditions that may develop and support continued business investment in a volatile commodity price environment. See 2018 Capital Investment Program, below.
See Item 1A. Risk Factors –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 cyclicalrelying 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 an extendedproduction.Recent Activities
During the period of suppressed commodity prices could have material adverse effects on2015-2018, we strategically repositioned our operations, our liquidity, and the price of our common stock.
Development and Operating Costs Third party oilfield service and supply costs are also subjectportfolio to supply and demand dynamics. During 2017, increasesfocus capital investment primarily in US onshore drillingplays, including the DJ and completion activity resulted in higher demand for oilfield services. As a result, the costs of drilling, equippingDelaware Basins and operating wells and infrastructure experienced some inflation, which,
along with commodity prices, impacted industry operating margins. Conversely, the industry has reduced capital-intensive offshore exploration and drilling activities in response to the commodity price environment. Demand for and costs associated with offshore conventional oil services have declinedEagle Ford Shale, and in our international offshore assets in the near-term, will likely not be subjectEastern Mediterranean and West Africa. The focus of our capital programs in these areas is expected to cost inflation.positively impact our future cash flows and margins.
Recent ActivitiesImplementationDuring 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. OverDuring 2018, we accomplished the past three years, we have made significant changes and enhancements to our business:following:
Portfolio Transformation,Activities, Including:
entered the liquids-rich Eagle Ford Shalesale of a 7.5% working interest in Tamar;
sale of our 50% interest in CONE Gathering LLC and Delaware Basin through the Rosetta Merger;
expanded our Delaware Basin position through the Clayton Williams Energy Acquisition;
exited the Marcellus Shale upstream and are exiting the Marcellus Shale midstream, thereby accelerating monetization of assets not attracting capital;
established the Noble Midstream business, including an initial public offering of Nobleinvestment in CNX Midstream Partners common units;
sale of our Gulf of Mexico assets;
expansion of new venture portfolio in both US onshore and executed the first asset drop down transaction; andinternational offshore locations;
accelerated DJ Basin value throughexecution of numerous acreage exchanges and sales.sales to secure more contiguous acreage positions within the DJ and Delaware Basins; and
completing the midstream Saddle Butte Acquisition, which expanded utilization of the Advantage Pipeline.
Operational Accomplishments, Including:
focused capital and resources on highest-margin assets within US onshore liquids plays and the Eastern Mediterranean;
sanctioned the initial phase ofprogressing Leviathan development withto approximately 75% completion and remaining on budget and on schedule to flow first natural gas sales targeted forby 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 impact of the Marcellus Shale upstream divestiture, increased proved reserves by more than 65% from 2016;
excluding the impact of the Marcellus Shale upstream divestiture, increased total US onshore sales volumes by more than 15% from 2016 and shiftedcontinuing shift to an oilier production mix, with more than 40%approximately 44% of our US onshore consolidated sales volumes attributable to crude oil;
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
improved well level and corporate returns with technology advancements and structural cost savings.received approval for the first large-scale CDP which will span our Mustang IDP area.
Financial Strength,Initiatives, Including:
proactiveBoard of Directors authorization to implement a $750 million share repurchase program and strategic actionsubsequent repurchase of 10 million shares of Noble Energy common stock, for $295 million, during the year;
increase in dividends to manage within cash flows;11 cents per Noble Energy common share for second, third and fourth quarters and paid dividends of $208 million during 2018;
made net repayments
repayment of 2016 through cash on hand, proceeds$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 asset sales, and cash generated by our midstream business;foreign operations with no US tax impact;
maintained a positive mitigation efforts for retained Marcellus Shale firm transportation contracts;
strong liquidity position including cash on hand and unused borrowing capacity; and
maintained our investment grade credit ratings.ratings and received improved outlooks from two agencies.
In summary, during 2017, we closed several strategic portfolio transactions demonstratingbelieve our continued focus on enhancing company margins and returns. Our current portfolio includes assets which are well-positioned on the industry cost of supply curve, offering growth at financially attractive rates of return. Operationally, we continuedcontinue to drive efficiencies in our US onshore drilling and completions, while advancing our Eastern Mediterranean and West Africa regional natural gas developments. Financially, we continuedcontinue to maintain our strong balance sheet and robust liquidity position.
Subsequent Events The Company has evaluated the period after the balance sheet date, noting no subsequent events or transactions that required recognition or disclosureposition while engaging in the financial statements, other than as previously disclosed or noted below.
Share Repurchase Program On February 15, 2018, we announced the Company's Board of Directors authorized a share repurchase program of $750 million which expires December 31, 2020. All purchases will be made in accordance with applicable securities laws from time to time in open market or private transactions, depending on market conditions, and may be discontinued at any time.
Gulf of Mexico DivestitureOn February 15, 2018, we announced the Company signed a definitive agreement to sell its assets in the Gulf of Mexico for cash consideration of $480 million. As part of the transaction, the buyer will assume all abandonment obligations associated with the properties which we estimate to approximate $230 million as of December 31, 2017. The net book value of the Gulf of Mexico assets as of December 31, 2017 was approximately $750 million. We expect to incur a charge in early 2018, subject to customary closing adjustments. The transaction is expected to close during second quarter 2018, contingent upon the buyer’s successful implementation of its contemplated restructuring, and will be effective as of January 1, 2018.
GSPAs - Israel Export On February 19, 2018, we executed two independent GSPAs for the sale of natural gas from the Leviathan and Tamar fields to Dolphinus Holdings Limited to supply natural gas in Egypt. Sales volumes under the GSPA associated with the Leviathan field are anticipated to begin at a firm rate of approximately 350 MMcf/d, gross, (approximately 139 MMcf/d, net) at the startup of the Leviathan project currently anticipated at the end of 2019. For the Tamar agreement, sales volumes are anticipated to begin at an interruptible rate of up to 350 MMcf/d, gross, (approximately 114 MMcf/d, net)
dependent upon gas availability beyond existing customer obligations in Israel and Jordan. The GSPA includes an option to convert the Tamar interruptible quantity to a firm-basis with a take or pay commitment. Both contracts are for a 10-year term and have pricing terms indexed to Brent crude, similar to other export contracts in the region. The GSPAs are subject to satisfaction of conditions precedent, including regulatory approvals and licenses, and finalizing gas transportation agreements. shareholder return initiatives.
OPERATING OUTLOOK
Growing Long-Term Value We believe the following guiding principles will contribute to growing long-term value:
Execution of a disciplined capital allocation process by:
| |
| ◦ | designing a flexible investment program aligned with the current commodity price environment; and |
| |
| ◦ | maintaining a strong balance sheet and liquidity position. |
Enhancing capital efficiencies through:by:
| |
| ◦ | utilizing our technical competencies and applying historical learnings from unconventional US shale plays to reduce US onshore finding and development costs; and |
| |
◦ | driving Delaware Basin economics through development cycle efficiencies.costs. |
Leveraging the benefits of our well-positioned and diversified portfolio, including:
| |
| ◦ | exercising investment optionality and flexibility afforded by our assets, certain of which are largely held by production; and |
| |
| ◦ | continuing portfolio optimization actions to maximize strategic value. |
Capitalizing on a currently low-cost offshore environment with execution of high-quality, long-cycle development projects, such as:
| |
| ◦ | progressing Leviathan Phase 1 field development.development and monetization of natural gas offshore West Africa. |
Maintaining financial strength through:
| |
| ◦ | focusing operational activities on high-margin, high-return assets; and |
| |
| ◦ | improving overall corporate returns; and |
| |
◦ | ensuring cash flow sources and uses remain balanced.returns. |
As we enter 2018, weWe currently expect that commodity price improvement will be limited 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.
We believe we have positionedour 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, position us for robust cash flow growth in 2020-2021.
However, if commodity prices decline are suppressed for an extended period of time and/or operating costs begin to rise,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 program or dividends, asset sales or otherwise. Our production and our stock price could decline as a result of these potential developments. See Item 1A. Risk Factors –The oil and gas industry is cyclical and an extended period of suppressed commoditycrude oil, NGL and natural gas prices are volatile. A reduction in these prices could have a material adverse effectseffect on our operations, our liquidity, and the price of our common stock. 2018 Production Production may be impacted by factors including:
commodity prices, which, if subject to decline, could result in currentOur 2019 production becoming uneconomic;
overall level and timing of capital expenditures which, as discussed below and dependent upon our drilling success, will impact near-term production volumes;
increased drilling activity, which may cause US onshore cost inflation pressure and result in certain current production becoming less profitable or uneconomic;
Israeli industrial and residential demand for electricity, whichtarget is largely impacted by weather conditions and the conversion of Israel's electricity portfolio from coal to natural gas;
timing of the divestiture of the remaining 7.5% working interest in the Tamar and Dalit fields, in accordance with the Framework, which will leave us with a 25% working interest and will accelerate value realization, but lower our forward sales volumes;range of 345 MBoe/d to 365 MBoe/d.
timing of crude oil and condensate liftings impacting sales volumes in West Africa;
natural field decline in US onshore, Gulf of Mexico and offshore Equatorial Guinea;
additional purchases of producing properties or divestments of operating assets;
potential weather-related volume curtailments due to hurricanes in the Gulf of Mexico and Gulf Coast areas, or winter storms and flooding impacting US onshore operations;
availability or reliability of supplier services, including access to support equipment and facilities, occurrence of pipeline disruptions, and/or potential pipeline and processing facility capacity constraints, which may cause delays, restrictions or interruptions in production and/or midstream processing;
timing and completion of midstream expansion projects by Noble Midstream Partners in areas that provide services to our assets;
malfunctions and/or mechanical failures at terminals or other US onshore delivery points;
impact of enhanced completion efforts for US onshore assets;
potential growth from participation in future, or decline from existing, non-operated wells;
abandonment of low-margin US onshore wells;
shut-in of US producing properties if storage capacity becomes unavailable; and
potential drilling and/or completion permit delays due to future regulatory changes.
20182019 Capital Investment Program
Exploration and Production ProgramOur 20182019 organic capital investment program is designed to deliver near and long-term value and is flexible in the current commodity price environment. Excluding capital funded by Noble Midstream Partners and acquisition capital related to the EMG Pipeline, our preliminary 20182019 organic capital program accommodates an investment levelis in the range of approximately $2.7$2.4 to $2.9$2.6 billion, with approximately 95%70% being allocated to US onshore development and approximately 20% to complete the Leviathan project in the Eastern Mediterranean. The remaining portion of our 2018the organic capital program is designated for otherNoble retained Midstream activities, including exploration for lease acquisition, seismicdrilling of a crude oil development well in West Africa, and other geological analysis in supportexploration and corporate activities.
2019 Budget Principles Our 20182019 organic capital program anticipates a similarlower level of investment directed to our US onshore assets, as compared with 2017.2018. 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, grow our high margin Delaware Basin position and invest capital supporting drilling commitments to retain leases in line with our strategy.value. In the Eastern Mediterranean, our 20182019 organic capital program, accommodates increasedexcluding acquisition capital related to the EMG Pipeline, includes the investment as we progress toward development of theneeded to complete Leviathan project. We expect our level of capital investment in the Leviathan project to peak in 2018 and will be supported by proceeds received from the divestiture of the remaining 7.5% working interest in the Tamar field.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 and NGL production;
operating and development costs;
production, drilling and delivery commitments, or other contractual obligations;
drilling results;
property acquisitions and divestitures;
exploration activity;
cash flows from operations including cash flows from potential midstream drop-down transactions;
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.
Impact of Recent Changes in US Tax Law
On December 22, 2017, the US Congress enacted the Tax Reform Legislation, making significant changes to US federal income tax law beginning in 2018. See Item 1A. Risk FactorsWhile we believe that certain aspects of the new law will positively impact our future after-tax earnings, primarily due to the lower federal statutory tax rate, the ultimate impact of the Tax Reform Legislation may differ from our estimates due to changes in interpretations and assumptions made by us as well as additional regulatory guidance that may be issued. See Item 8. Financial Statements and Supplementary Date – Note 11. Income Taxes.Potential for Future Impairments
We have had in the past, and may incur in the future, various impairments of proved and unproved properties, related to the following:
Exploration Activities and Unproved Properties We may impair and/or relinquish certain undeveloped leases prior to expiration based upon changes in exploration plans, timing and extent of development activities, availability of capital and suitable rig and drilling equipment, resource potential, comparative economics, changing regulations and/or other factors. In addition, in the event we conclude that an exploratory well did not encounter hydrocarbons or that a discovery or prospect is not economically or operationally viable, the associated capitalized exploratory well costs would be charged to expense.
Development Concept Selection Costs We may write-off costs related to certain development concepts, including costs of related pre-FEED and FEED studies, associated with significant offshore projects, particularly those in remote or under-developed areas, when such development concepts are eliminated from further consideration based on the
determination of the final development concept or when the concept itself is determined to be economically unfeasible.
Producing PropertiesWe may impair a proved property based on a decrease in forward commodity prices, or widening of basis differentials, or an increase in abandonment costs, among other factors.
Divestments We may periodically divest certain assets to reposition our portfolio. When properties meet the criteria for reclassification as assets held for sale, they are valued at the lower of net book value or anticipated sales proceeds less transaction-related costs to sell. Impairment expense would be recorded for any excess of net book value over anticipated sales proceeds less transaction-related costs to sell. In addition, a further loss, which could be material, could occur upon closing of a sales transaction.
RESULTS OF OPERATIONS – E&P
Highlights for our E&P business were as follows:
20172018 Significant E&P Operating Highlights Included:
total average dailyconsolidated sales volumes of 381346 MBoe/d;d, net;
record average daily sales volumes for US onshore crude oil of 90109 MBbl/d;d, net; and
average daily sales volumes for natural gas of 272 MMcf/approximately 1.0 Bcfe/d, net, ingross, offshore Israel, and an all-time record for full year average daily gross sales volumes for natural gas of 956 MMcfe/d, primarily from the Tamar field.
20172018 E&P Financial Results Included:
average realized crude oil price increase of 23%25% as compared to 2016;with 2017;
average realized NGL price increase of 56%10% as compared to 2016;with 2017;
average realized natural gas price increasedecrease of 24%8% as compared with 2017;
goodwill impairment charge of $1.3 billion attributable to 2016;the Texas reporting unit (associated with the Clayton Williams Energy Acquisition);
pre-tax lossincome of $1.8 billion,$119 million, as compared with pre-tax loss of $1.3$1.8 billion for 2016;2017; and
capital expenditures, of $2.4 billion, excluding acquisitions, of $2.8 billion, as compared with $1.2$2.4 billion for 2016.2017.
Following is a summarized statement of operations for our E&P business:
| | | | Year Ended December 31, | Year Ended December 31, |
| (millions) | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Oil, NGL and Gas Sales to Third Parties | $ | 4,060 |
| | $ | 3,389 |
| | $ | 3,093 |
| $ | 4,461 |
| | $ | 4,060 |
| | $ | 3,389 |
|
| Income from Equity Method Investees | 120 |
| | 50 |
| | 39 |
| 132 |
| | 120 |
| | 50 |
|
| Total Revenues | 4,180 |
| | 3,439 |
| | 3,132 |
| 4,613 |
| | 4,180 |
| | 3,439 |
|
Production Expense | 1,270 |
| | 1,200 |
| | 1,067 |
| 1,358 |
| | 1,270 |
| | 1,200 |
|
| Exploration Expense | 188 |
| | 925 |
| | 488 |
| 129 |
| | 188 |
| | 925 |
|
| Depreciation, Depletion and Amortization | 1,965 |
| | 2,395 |
| | 2,073 |
| 1,819 |
| | 1,965 |
| | 2,395 |
|
Loss on Marcellus Shale Upstream Divestiture (1) | 2,379 |
| | — |
| | — |
| |
| Loss on Marcellus Shale Upstream Divestiture and Other | | — |
| | 2,286 |
| | — |
|
Gain on Divestitures, Net (2) | | (340 | ) | | (326 | ) | | (238 | ) |
Asset Impairments (2) | 70 |
| | 92 |
| | 533 |
| 169 |
| | 70 |
| | 92 |
|
Goodwill Impairment | | 1,281 |
| | — |
| | — |
|
| (Gain) Loss on Commodity Derivative Instruments | (63 | ) | | 139 |
| | (501 | ) | (63 | ) | | (63 | ) | | 139 |
|
Goodwill Impairment | — |
| | — |
| | 779 |
| |
Clayton Williams Energy Acquisition Expenses (3) | 100 |
| | — |
| | — |
| |
| Clayton Williams Energy Acquisition Expenses | | — |
| | 100 |
| | — |
|
| Income (Loss) Before Income Taxes | (1,803 | ) | | (1,271 | ) | | (1,699 | ) | 119 |
| | (1,803 | ) | | (1,271 | ) |
| |
(1) | The adoption of ASC 606 on January 1, 2018 had a de minimis impact on revenues and production expense for 2018.See Item 8. Financial Statements and Supplementary Data – Note 4. Acquisitions, Divestitures and Merger. |
Revenues
Oil, Gas and NGL Sales AgreementsWe generally sell crude oil, natural gas, and NGLs under two types of agreements common in our industry. Both types of agreements may include transportation charges. One type of agreement is a netback agreement, under which we sell crude oil and natural gas at the wellhead and receive a price, net of transportation expense incurred by the purchaser. In the case of NGLs, we may receive a price from the purchaser, which is net of fractionation and processing costs. We record crude oil, natural gas and NGL sales without deductions relating to transportation, fractionation or processing. These deductions are recorded as production expense.
In addition, commodity prices we receive may be reduced by location-basis differentials, which can be significant. For example, transportation bottlenecks or infrastructure limitations may increase demand for available transportation and gathering facilities, which could lead to competitive pricing between operators of a particular area. As a result of location-basis differentials, our reported sales prices may differ significantly from published commodity price benchmarks for the same period.
Average Oil, NGL and Gas and NGL SalesVolumes and PricesAverage daily sales volumes and average realized sales prices were as follows: | | | | Sales Volumes | | Average Realized Sales Prices | Sales Volumes (1) | | Average Realized Sales Prices (1) |
| | Crude Oil & Condensate (MBbl/d) | | NGLs
(MBbl/d) | | Natural Gas (MMcf/d) | | Total (MBoe/d) (1) | | 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, 2018 |
United States (2) | | 114 |
| | 62 |
| | 472 |
| | 255 |
| | $ | 61.12 |
| | $ | 25.88 |
| | $ | 2.53 |
|
| Eastern Mediterranean | | — |
| | — |
| | 237 |
| | 40 |
| | — |
| | — |
| | 5.47 |
|
West Africa (3) | | 16 |
| | — |
| | 213 |
| | 51 |
| | 68.53 |
| | — |
| | 0.27 |
|
| Total Consolidated Operations | | 130 |
| | 62 |
| | 922 |
| | 346 |
| | 62.01 |
| | 25.88 |
| | 2.76 |
|
Equity Investees (4) | | 2 |
| | 5 |
| | — |
| | 7 |
| | 68.99 |
| | 42.14 |
| | — |
|
| Total | | 132 |
| | 67 |
| | 922 |
| | 353 |
| | $ | 62.10 |
| | $ | 27.18 |
| | $ | 2.76 |
|
Year Ended December 31, 2017 | | United States | 111 |
| | 58 |
| | 607 |
| | 270 |
| | $ | 49.11 |
| | $ | 23.40 |
| | $ | 3.02 |
| 111 |
| | 58 |
| | 607 |
| | 270 |
| | $ | 49.11 |
| | $ | 23.40 |
| | $ | 3.02 |
|
| Israel | — |
| | — |
| | 272 |
| | 46 |
| | — |
| | — |
| | 5.32 |
| |
Equatorial Guinea (2) | 18 |
| | — |
| | 239 |
| | 57 |
| | 53.68 |
| | — |
| | 0.27 |
| |
| Eastern Mediterranean | | — |
| | — |
| | 272 |
| | 46 |
| | — |
| | — |
| | 5.32 |
|
West Africa (3) | | 18 |
| | — |
| | 239 |
| | 57 |
| | 53.68 |
| | — |
| | 0.27 |
|
| Total Consolidated Operations | 129 |
| | 58 |
| | 1,118 |
| | 373 |
| | 49.73 |
| | 23.40 |
| | 3.01 |
| 129 |
| | 58 |
| | 1,118 |
| | 373 |
| | 49.73 |
| | 23.40 |
| | 3.01 |
|
Equity Investee (3) | 2 |
| | 6 |
| | — |
| | 8 |
| | 55.13 |
| | 38.48 |
| | — |
| |
Equity Investees (4) | | 2 |
| | 6 |
| | — |
| | 8 |
| | 55.13 |
| | 38.48 |
| | — |
|
| Total | 131 |
| | 64 |
| | 1,118 |
| | 381 |
| | $ | 49.84 |
| | $ | 24.81 |
| | $ | 3.01 |
| 131 |
| | 64 |
| | 1,118 |
| | 381 |
| | $ | 49.84 |
| | $ | 24.81 |
| | $ | 3.01 |
|
Year Ended December 31, 2016 | | United States | 99 |
| | 54 |
| | 881 |
| | 301 |
| | $ | 39.59 |
| | $ | 14.92 |
| | $ | 2.11 |
| 99 |
| | 54 |
| | 881 |
| | 301 |
| | $ | 39.59 |
| | $ | 14.92 |
| | $ | 2.11 |
|
| Israel | — |
| | — |
| | 281 |
| | 47 |
| | — |
| | — |
| | 5.21 |
| |
Equatorial Guinea (2) | 26 |
| | — |
| | 235 |
| | 65 |
| | 43.54 |
| | — |
| | 0.27 |
| |
| 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 |
| 125 |
| | 54 |
| | 1,397 |
| | 413 |
| | 40.39 |
| | 14.92 |
| | 2.42 |
|
Equity Investee (3) | 2 |
| | 5 |
| | — |
| | 7 |
| | 45.44 |
| | 26.30 |
| | — |
| |
Equity Investees (4) | | 2 |
| | 5 |
| | — |
| | 7 |
| | 45.44 |
| | 26.30 |
| | — |
|
| Total | 127 |
| | 59 |
| | 1,397 |
| | 420 |
| | $ | 40.46 |
| | $ | 15.96 |
| | $ | 2.42 |
| 127 |
| | 59 |
| | 1,397 |
| | 420 |
| | $ | 40.46 |
| | $ | 15.96 |
| | $ | 2.42 |
|
| Year Ended December 31, 2015 | |
| United States | 81 |
| | 39 |
| | 708 |
| | 237 |
| | $ | 43.46 |
| | $ | 13.91 |
| | $ | 2.10 |
| |
| Israel | — |
| | — |
| | 252 |
| | 42 |
| | — |
| | — |
| | 5.34 |
| |
Equatorial Guinea (2) | 31 |
| | — |
| | 227 |
| | 69 |
| | 48.85 |
| | — |
| | 0.27 |
| |
| Total Consolidated Operations | 112 |
| | 39 |
| | 1,187 |
| | 348 |
| | 45.00 |
| | 13.91 |
| | 2.44 |
| |
Equity Investee (3) | 2 |
| | 5 |
| | — |
| | 7 |
| | 48.85 |
| | 28.40 |
| | — |
| |
| Total | 114 |
| | 44 |
| | 1,187 |
| | 355 |
| | $ | 45.05 |
| | $ | 15.59 |
| | $ | 2.44 |
| |
| |
(1) | Natural gas is converted |
| |
| ◦ | increases in NGL revenues, and corresponding increase in production expense, 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$7 million for a barrel of crude oil equivalent for US2018; |
| |
| ◦ | decreases in natural gas revenues, and NGLs is significantly less than the pricecorresponding decreases in production expense, of $7 million for a barrel of crude oil. In Israel, we sell2018; |
| |
| ◦ | increases in NGL and natural gas under contracts where the majoritysales volumes of the price is fixed, resulting5 MBbl/d and 31MMcf/d, respectively, for 2018; and |
| |
| ◦ | reductions in less commodity price disparity.average realized NGL and natural gas sales prices of $1.76/Bbl and $0.12/Mcf, respectively, for 2018. |
| |
(2) | Natural gas from the Alba field is under contract |
| |
(4) | Volumes represent sales of condensate and LPG from Alba Plantthe LPG plant in Equatorial Guinea. See Income from Equity Method Investees. |
An analysis of revenues from sales of crude oil, NGLs and natural gas and NGLs is as follows: |
| | | | | | | | | | | | | | | | |
| | | Crude Oil & Condensate | | NGLs | | Natural Gas | | Total |
| (millions) | | | | | | | | |
| 2015 Sales Revenues | | $ | 1,840 |
| | $ | 197 |
| | $ | 1,056 |
| | $ | 3,093 |
|
| Changes due to | | | | | | | | |
| Increase in Sales Volumes | | 153 |
| | 84 |
| | 190 |
| | 427 |
|
| (Decrease) Increase in Sales Prices | | (139 | ) | | 15 |
| | (7 | ) | | (131 | ) |
| 2016 Sales Revenues | | $ | 1,854 |
| | $ | 296 |
| | $ | 1,239 |
| | $ | 3,389 |
|
| Changes due to | | | | | | | | |
| Increase (Decrease) in Sales Volumes | | 55 |
| | 17 |
| | (182 | ) | | (110 | ) |
| Increase in Sales Prices | | 437 |
| | 180 |
| | 164 |
| | 781 |
|
| 2017 Sales Revenues | | $ | 2,346 |
| | $ | 493 |
| | $ | 1,221 |
| | $ | 4,060 |
|
|
| | | | | | | | | | | | | | | | |
| (millions) | | Crude Oil & Condensate | | NGLs | | Natural Gas | | Total |
| Year Ended December 31, 2016 | | $ | 1,854 |
| | $ | 296 |
| | $ | 1,239 |
| | $ | 3,389 |
|
| Changes due to | | | | | | | | |
| Increase (Decrease) in Sales Volumes | | 55 |
| | 17 |
| | (182 | ) | | (110 | ) |
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 |
|
Crude Oil and Condensate Sales RevenuesRevenues from crude oil and condensate sales increased in 2018 as compared with 2017 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:
23% increase in average realized prices due to the partial rebalancing of global supply and demand factors;higher US onshore sales volumes of 16 MBbl/d, including 5 MBbl/d contributed by recently acquired Clayton Williams Energy assets, primarily attributable to increased development and enhanced well design and completion techniques; and
higher sales volumes of 2 MBbl/d due to full year of production at Gunflint, a Gulf of Mexico project that started production in July 2016;
partially offset by:
lower sales volumes of 14 MBbl/d primarily due to natural field decline in the Gulf of Mexico and Equatorial Guinea.
NGL Sales RevenuesRevenues from crude oil and condensateNGL sales remained relatively flatincreased in 20162018 as compared with 20152017 due to the following:
higher US onshore sales volumes of 96 MBbl/d in the Eagle Ford Shale and Delaware Basin,(exclusive of 5 MBbl/d from adoption of ASC 606) primarily attributable to full year consolidation followingdevelopment activities in the Rosetta Merger;Delaware and DJ Basins;
sales volumes from$7 million increase associated with the Big Bend and Dantzler developments (Gulfadoption of Mexico), which began producing fourth quarter 2015 and contributed 12 MBbl/d, net, collectively in 2016; and
sales volume from the start up of the Gulf of Mexico Gunflint development in July 2016 which contributed 3 MBbl/d;ASC 606;
partially offset by:
10% decrease in total consolidated average realized prices, primarilylower sales volumes of 5 MBbl/d due to the declinedivestiture of the Marcellus Shale upstream assets in global crude oil prices that began in the second half of 2014 and continued into 2016; andquarter 2017.
decrease in sales volumes due to natural field decline at the Aseng and Alen fields, offshore Equatorial Guinea.
NGL Sales RevenuesRevenues from NGL sales increased in 2017 increased as compared with 2016 due to the following:
56% increase in average realized prices due to the partial rebalancing of global supply and demand factors;higher US onshore sales volumes of 7 MBbl/d, including 1 MBbl/d contributed by recently acquired Clayton Williams Energy assets, primarily attributable to increased development and enhanced well design and completion techniques;
partially offset by:
lower sales volumes of 4 MBbl/d due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017.
Natural Gas Sales RevenuesRevenues from NGLnatural gas sales increaseddecreased in 20162018 as compared with 20152017 due to the following:
higherlower sales volumes of 174 MMcf/d due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017;
lower Gulf of Mexico sales volumes of 14 MBbl/MMcf/d resulting 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 Eagle Ford ShaleTamar 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 Delaware Basin, primarily attributable to a full yeartiming of production as well as increased development activity;field maintenance; and
7% increase8% decrease in total consolidated average realized prices primarily due to the impact of increased US onshore supply;
partially offset by:
higher spot pricesUS onshore sales volumes of 30 MMcf/d (exclusive of 31 MMcf/d from adoption of ASC 606) primarily attributable to development activities in the Marcellus Shale;Delaware and DJ Basins; and
higher sales volumes of 2 MBbl/drelated to our remaining working interest in the DJ Basin, primarily attributableIsrael due to increased demand for power as well productivity dueas conversion of facilities from use of coal to enhanced completion techniques and increased processing capacity;natural gas.
partially offset by:
slightly lower sales volumes in the Marcellus Shale due to the higher dry gas composition of wells that were brought online in 2016.
Natural Gas Sales RevenuesRevenues from natural gas sales decreased slightly in 2017 as compared with 2016 due to the following:
lower sales volumes of 312 MMcf/d due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017; and
lower sales volumes of 29 MMcf/d as a result of the sale of a 3.5% working interest in the Tamar field offshore Israel, in December 2016, partially offset by higher gross sales volumes from the field;
partially offset by:
24% increase in average realized prices due to the partial rebalancing of global supply and demand factors;higher US onshore sales volumes of 40 MMcf/d, including 6 MMcf/d contributed by recently acquired Clayton Williams Energy assets.
Revenues from natural gas sales in 2016 as compared with 2015 due to the following:
higher sales volumes of 93 MMcf/d in the Marcellus Shale, primarily attributable to well completion and infrastructure development;
higher sales volumes of 81 MMcf/d in the Eagle Ford Shale and Delaware Basin, primarily attributable to full year consolidation following the Rosetta Merger;
record sales volumes from the Tamar field, offshore Israel, which contributed an incremental 29 MMcf/d, in response to higher power generation needs; and
higher sales volumes offshore Equatorial Guinea due to the completion of the Alba B3 compression project.
Income from Equity Method InvesteesOur share of operations of equity method investees waswere as follows: | | | | | Year Ended December 31, | | Year Ended December 31, |
| | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| Net Income (in millions) | | | | | | | | | | | | |
| AMPCO and Affiliates | | $ | 58 |
| | $ | 16 |
| | $ | 8 |
| | $ | 64 |
| | $ | 58 |
| | $ | 16 |
|
| Alba Plant | | 65 |
| | 34 |
| | 31 |
| | 71 |
| | 65 |
| | 34 |
|
| Dividends (in millions) | | | | | | | | | | | | |
| AMPCO and Affiliates | | 47 |
| | 16 |
| | 31 |
| | $ | 63 |
| | $ | 47 |
| | $ | 16 |
|
| Alba Plant | | 68 |
| | 40 |
| | 29 |
| | 93 |
| | 68 |
| | 40 |
|
| Sales Volumes | | | | | | | | | | | | |
| Methanol (MMgal) | | 163 |
| | 162 |
| | 117 |
| | 149 |
| | 163 |
| | 162 |
|
| Condensate (MBbl/d) | | 2 |
| | 2 |
| | 2 |
| | 2 |
| | 2 |
| | 2 |
|
| LPG (MBbl/d) | | 6 |
| | 5 |
| | 5 |
| | 5 |
| | 6 |
| | 5 |
|
| Average Realized Prices | | | | | | | | | | | | |
| Methanol (per gallon) | | $ | 0.97 |
| | $ | 0.63 |
| | $ | 0.92 |
| | $ | 1.14 |
| | $ | 0.97 |
| | $ | 0.63 |
|
| Condensate (per Bbl) | | 55.13 |
| | 45.44 |
| | 48.85 |
| | 68.99 |
| | 55.13 |
| | 45.44 |
|
| LPG (per Bbl) | | 38.48 |
| | 26.30 |
| | 28.40 |
| | 42.14 |
| | 38.48 |
| | 26.30 |
|
Changes for 2018 as compared with 2017 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 realized LPG prices.
Changes for 2017 as compared with 2016 included the following:
increase in net income from AMPCO and affiliates increased primarily due to higher realized methanol prices; and
increase in net income from Alba Plant increased primarily due to higher LPG sales volumes and higher realized commodity prices.
Changes for 2016 as compared with 2015 included the following:
net income from AMPCO and affiliates increased in 2016 as compared with 2015 primarily due to higher methanol sales volumes, partially offset by lower methanol prices; and
net income from Alba Plant remained relatively flat.
Production ExpenseComponents of production expense were as follows: |
| | | | | | | | | | | | | | | | | | | | | | | |
| (millions, except unit rate) | Total per BOE (1) | | Total | | United States (1) | | Israel | | Equatorial Guinea | | Other Int'l(2) |
| Year Ended December 31, 2017 | | | | | | | | | | | |
Lease Operating Expense (3) | $ | 4.29 |
| | $ | 585 |
| | $ | 466 |
| | $ | 29 |
| | $ | 90 |
| | $ | — |
|
| Production and Ad Valorem Taxes | 0.99 |
| | 135 |
| | 135 |
| | — |
| | — |
| | — |
|
| Gathering, Transportation and Processing Expense | 4.04 |
| | 550 |
| | 550 |
| | — |
| | — |
| | — |
|
| Total Production Expense | $ | 9.32 |
| | $ | 1,270 |
| | $ | 1,151 |
| | $ | 29 |
| | $ | 90 |
| | $ | — |
|
| Total Production Expense per BOE | | | $ | 9.32 |
| | $ | 11.68 |
| | $ | 1.74 |
| | $ | 4.28 |
| | $ | — |
|
| Year Ended December 31, 2016 | |
| | |
| | |
| | |
| | |
| | |
|
Lease Operating Expense (3) | $ | 3.72 |
| | $ | 560 |
| | $ | 418 |
| | $ | 37 |
| | $ | 105 |
| | $ | — |
|
| Production and Ad Valorem Taxes | 0.50 |
| | 76 |
| | 76 |
| | — |
| | — |
| | — |
|
| Gathering, Transportation and Processing Expense | 3.73 |
| | 564 |
| | 564 |
| | — |
| | — |
| | — |
|
| Total Production Expense | $ | 7.95 |
| | $ | 1,200 |
| | $ | 1,058 |
| | $ | 37 |
| | $ | 105 |
| | $ | — |
|
| Total Production Expense per BOE | | | $ | 7.95 |
| | $ | 9.63 |
| | $ | 2.14 |
| | $ | 4.42 |
| | $ | — |
|
| Year Ended December 31, 2015 | | | | | | | | | | | |
Lease Operating Expense (3) | $ | 4.52 |
| | $ | 575 |
| | $ | 398 |
| | $ | 42 |
| | $ | 131 |
| | $ | 4 |
|
| Production and Ad Valorem Taxes | 0.99 |
| | 126 |
| | 126 |
| | — |
| | — |
| | — |
|
| Gathering, Transportation and Processing Expense | 2.88 |
| | 366 |
| | 366 |
| | — |
| | — |
| | — |
|
| Total Production Expense | $ | 8.39 |
| | $ | 1,067 |
| | $ | 890 |
| | $ | 42 |
| | $ | 131 |
| | $ | 4 |
|
| Total Production Expense per BOE | | | $ | 8.39 |
| | $ | 10.29 |
| | $ | 2.72 |
| | $ | 5.21 |
| | N/M |
|
N/M Amount is not meaningful. |
| | | | | | | | | | | | | | | | | | | |
| (millions, except unit rate) | 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 |
|
| Production and Ad Valorem Taxes | 1.46 |
| | 184 |
| | 184 |
| | — |
| | — |
|
Gathering, Transportation and Processing (4) | 4.22 |
| | 533 |
| | 533 |
| | — |
| | — |
|
| Other Royalty Expense | 0.30 |
| | 38 |
| | 38 |
| | — |
| | — |
|
| Total Production Expense | $ | 10.76 |
| | $ | 1,358 |
| | $ | 1,235 |
|
| $ | 26 |
|
| $ | 97 |
|
| Total Production Expense per BOE | | | $ | 10.76 |
| | $ | 13.28 |
| | $ | 1.79 |
| | $ | 5.20 |
|
| Year Ended December 31, 2017 | |
| | |
| | |
| | |
| | |
|
Lease Operating Expense (3) | $ | 4.29 |
| | $ | 585 |
| | $ | 466 |
| | $ | 29 |
| | $ | 90 |
|
| Production and Ad Valorem Taxes | 0.84 |
| | 115 |
| | 115 |
| | — |
| | — |
|
| Gathering, Transportation and Processing | 4.04 |
| | 550 |
| | 550 |
| | — |
| | — |
|
| Other Royalty Expense | 0.15 |
| | 20 |
| | 20 |
| | — |
| | — |
|
| Total Production Expense | $ | 9.32 |
| | $ | 1,270 |
| | $ | 1,151 |
| | $ | 29 |
| | $ | 90 |
|
| Total Production Expense per BOE | | | $ | 9.32 |
| | $ | 11.68 |
| | $ | 1.74 |
| | $ | 4.28 |
|
| 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. |
| |
(2)
| Other International includes the North Sea in 2015. |
| |
(3) | Lease operating expense includes oil and gas operating costs (labor, fuel, repairs, replacements, saltwater disposal and other related lifting costs) and workover expense. |
Lease Operating Expense Lease operating expense increased in 2018 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 2016 primarily due to the following:
increase of $82 million in US onshore, primarily in the DJ Basin, Delaware Basin and Eagle Ford Shale due to increased activity;
partially offset by:
decrease of $19 million due toresulting 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 offshore Israel, following the partial divestiture in December 2016.
Lease operating expense decreased in 2016 as compared with 2015 due to the following:
decrease of $92 million in US onshore, primarily in the DJ Basin and Marcellus Shale, and $27 million offshore Equatorial Guinea due to cost reduction initiatives, including lower equipment utilization and saltwater disposal costs;
partially offset by:
increase of $74 million attributable to new production from US onshore and Gulf of Mexico development activities; and
increase of $38 million related to the acquisition of Eagle Ford Shale and Delaware Basin production third quarter 2015.
Production and Ad Valorem Tax ExpenseProduction and ad valorem taxes increased in 2018 as compared with 2017, primarily due to higher commodity prices.
Production and ad valorem taxes increased in 2017 as compared with 2016, primarily due to higher commodity prices and a $28 million US onshore severance tax refund recorded in first quarter 2016 versus a $7 million US onshore severance tax charge recorded in first quarter 2017.
Production and ad valorem taxes decreased in 2016 as compared with 2015, primarily due to lower revenues and a US onshore severance tax refund, both driven by a decline in US commodity prices.
Gathering, Transportation and Processing Expense Gathering, transportation and processing expense 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.
Gathering, transportation and processingOther Royalty ExpenseOther royalty expense increased in 20162018 as compared with 20152017, primarily due to:
increase of $66 million related to higher production from ourcommodity 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 assets;
increase of $57 million related to changeupstream assets in mix of transportation methods used for our DJ Basin production;
increase of $49 million related to higher production from our Eagle Ford Shale assets acquired thirdsecond quarter 2015;2017 and
increase of $17 million related to production from new Gulf of Mexico projects at Big Bend and Dantzler (which began producing fourthassets in second quarter 2015) and Gunflint (which began producing2018, which lowered our average production expense per BOE. These impacts were offset by an increase in July 2016).volumes from the higher cost Delaware Basin.
Unit Rate Per BOEProduction expense on a per BOE basis increased in 2017 as compared towith 2016, primarily due to the increases in certain production expenses noted above. In addition, the Marcellus Shale upstream divestiture resulted in the removal of lower-cost, natural gas-focused sales volumes from our portfolio, while an increase in Delaware Basin and Eagle Ford Shale volumes contributed higher-cost, crude oil-focused sales volumes, thereby increasing our average production expense per BOE. Also, higher commodity prices led to higher production and ad valorem taxes per BOE.
The unit rate of total production expense per BOE decreased for 2016 as compared with 2015, primarily driven by lower production and ad valorem taxes as a result of lower commodity prices and lower lease operating expenses as a result of cost reductions in certain areas, such as equipment utilization and saltwater disposal. The decrease in the unit rate per BOE was partially offset by higher transportation and gathering expenses due to higher-cost production volumes from certain US onshore assets.
Exploration ExpenseComponents of exploration expense were as follows: | | | (millions) | Total | | United States | | Eastern Mediter-ranean (1) | | West Africa (2) | | Other Int'l (3) | Total | | United States | | Eastern Mediter-ranean | | West Africa | | Other Int'l |
| Year Ended December 31, 2017 | | | |
| | |
| | |
| | |
| |
| Year Ended December 31, 2018 | | | | |
| | |
| | |
| | |
|
| Leasehold Impairment and Amortization | $ | 62 |
| | $ | 60 |
| | $ | — |
| | $ | — |
| | $ | 2 |
| $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
|
Dry Hole Cost (4) | 9 |
| | — |
| | — |
| | — |
| | 9 |
| |
Dry Hole Cost (1) | | 1 |
| | 1 |
| | — |
| | — |
| | — |
|
| Seismic, Geological and Geophysical | 27 |
| | 8 |
| | — |
| | — |
| | 19 |
| 22 |
| | 8 |
| | 3 |
| | — |
| | 11 |
|
| Staff Expense | 55 |
| | 1 |
| | 2 |
| | 4 |
| | 48 |
| 54 |
| | 41 |
| | 2 |
| | 5 |
| | 6 |
|
Other (5) | 35 |
| | 33 |
| | — |
| | 1 |
| | 1 |
| |
Other (2) | | 51 |
| | (3 | ) | | 2 |
| | 1 |
| | 51 |
|
| Total Exploration Expense | $ | 188 |
| | $ | 102 |
| | $ | 2 |
| | $ | 5 |
| | $ | 79 |
| $ | 129 |
| | $ | 48 |
| | $ | 7 |
| | $ | 6 |
| | $ | 68 |
|
| Year Ended December 31, 2016 | | | | | | | | | | |
| Year Ended December 31, 2017 | | | | | | | | | | |
| Leasehold Impairment and Amortization | $ | 148 |
| | $ | 123 |
| | $ | — |
| | $ | — |
| | $ | 25 |
| $ | 62 |
| | $ | 60 |
| | $ | — |
| | $ | — |
| | $ | 2 |
|
Dry Hole Cost (4)(1) | 579 |
| | 85 |
| | 26 |
| | 468 |
| | — |
| 9 |
| | — |
| | — |
| | — |
| | 9 |
|
| Seismic, Geological and Geophysical | 76 |
| | — |
| | — |
| | 10 |
| | 66 |
| 27 |
| | 8 |
| | — |
| | — |
| | 19 |
|
| Staff Expense | 77 |
| | 3 |
| | 1 |
| | 5 |
| | 68 |
| 55 |
| | 1 |
| | 2 |
| | 4 |
| | 48 |
|
Other (5)(2) | 45 |
| | 34 |
| | 7 |
| | — |
| | 4 |
| 35 |
| | 33 |
| | — |
| | 1 |
| | 1 |
|
| Total Exploration Expense | $ | 925 |
| | $ | 245 |
| | $ | 34 |
| | $ | 483 |
| | $ | 163 |
| $ | 188 |
| | $ | 102 |
| | $ | 2 |
| | $ | 5 |
| | $ | 79 |
|
| Year Ended December 31, 2015 | | | |
| | |
| | |
| | |
| |
| Year Ended December 31, 2016 | | | | |
| | |
| | |
| | |
|
| Leasehold Impairment and Amortization | $ | 113 |
| | $ | 105 |
| | $ | 5 |
| | $ | 3 |
| | $ | — |
| $ | 148 |
| | $ | 123 |
| | $ | — |
| | $ | — |
| | $ | 25 |
|
Dry Hole Cost (4) | 266 |
| | 93 |
| | — |
| | 33 |
| | 140 |
| |
Dry Hole Cost (1) | | 579 |
| | 85 |
| | 26 |
| | 468 |
| | — |
|
| Seismic, Geological and Geophysical | 34 |
| | 5 |
| | — |
| | 10 |
| | 19 |
| 76 |
| | — |
| | — |
| | 10 |
| | 66 |
|
| Staff Expense | 43 |
| | — |
| | 1 |
| | — |
| | 42 |
| 77 |
| | 3 |
| | 1 |
| | 5 |
| | 68 |
|
Other (5) | 32 |
| | — |
| | 6 |
| | — |
| | 26 |
| |
Other (2) | | 45 |
| | 34 |
| | 7 |
| | — |
| | 4 |
|
| Total Exploration Expense | $ | 488 |
| | $ | 203 |
| | $ | 12 |
| | $ | 46 |
| | $ | 227 |
| $ | 925 |
| | $ | 245 |
| | $ | 34 |
| | $ | 483 |
| | $ | 163 |
|
| |
(1) | Eastern Mediterranean includes Israel and Cyprus. |
| |
(2)
| West Africa includes Equatorial Guinea, Cameroon and Gabon. |
| |
(3)
| Other International includes Newfoundland, Suriname and other new ventures. |
| |
(5)(2)
| Includes lease rental and other exploration expense. |
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.
ExplorationDepreciation, Depletion and Amortization ExpenseDepreciation, Depletion and Amortization (DD&A) expense for 2015 included: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 |
| | $ | — |
|
leasehold impairment(1) DD&A expense including the write-offincludes accretion of our northeast Nevada leasesdiscount on AROs of $21 million;
US dry hole cost including amounts related to northeast Nevada exploration efforts which we elected to discontinue after assessing commercial viability$33 million in the current commodity price environment; and
dry hole cost including the Cheetah well, offshore West Africa, and Other International dry hole cost.
Exploration expense included stock-based compensation expense of $72018, $47 million in 2017, $10and $48 million in 2016 and $13 million in 2015.2016.
Depreciation, Depletion and AmortizationTotal DD&A expense decreased in 2018 as compared with 2017 primarily due to the following:
decrease of $223 million due to both lower sales volumes in the Gulf of Mexico resulting from natural field decline and classification of the assets as held for sale in first quarter 2018, 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; and
decrease of $90 million due to the Marcellus Shale upstream divestiture in second quarter 2017;
partially offset by:
higher 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.
The unit rate per BOE for 2018 was
flat as
follows:compared with 2017, primarily due to the increased development activity in the Delaware Basin resulting in higher depletable basis and the sales of lower-cost production from our 7.5% interest in the Tamar field in first quarter 2018 and the Marcellus Shale upstream assets in second quarter 2017, 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.
|
| | | | | | | | | | | | | | | | | | | |
| (millions, except unit rate) | Total | | United
States | | Eastern
Mediter- ranean | | West
Africa | | Other Int'l |
| Twelve Months 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 |
| | N/M |
|
| Twelve Months 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 |
| | N/M |
|
| Twelve Months Ended December 31, 2015 | | | | | | | | | |
| DD&A Expense | $ | 2,073 |
| | $ | 1,677 |
| | $ | 70 |
| | $ | 326 |
| | $ | — |
|
Unit Rate per BOE (1) | $ | 16.29 |
| | $ | 19.40 |
| | $ | 4.53 |
| | $ | 12.93 |
| | N/M |
|
N/M Amount is not meaningful.
| |
(1)
| DD&A expense includes accretion of discount on asset retirement obligations of $47 million in 2017, $48 million in 2016, and $43 million in 2015. |
Total DD&A expense decreased in 2017 as compared with 2016 primarily due to the following:
| |
• | year-end reserve additions, primarily in US onshore due to enhanced well design and completion techniques in our horizontal drilling program and globally due to positive price revisions; year-end reserve additions, primarily in US onshore due to enhanced well design and completion techniques in our horizontal drilling program and globally due to positive price revisions. For more information, see reserves discussion in Supplemental Oil and Gas Information (Unaudited); |
slightly lower sales volumes in the DJ Basin and the impact of certain property divestitures since the second quarter 2016;
decrease of $291 million due to the Marcellus Shale upstream divestiture in second quarter 2017, which reduced 2017 DD&A expense by $291 million;2017;
decrease of $7 million due to the sale of a 3.5% working interest in the Tamar field offshore Israel, in December 2016, which reduced 2017 DD&A expense by approximately $7 million;2016;
decrease of $37 million due to a reduction in depletable costs of $153 million in the second quarter 2017 due to the reallocation of common asset costs from the Alen field, offshore Equatorial Guinea, to the West Africa natural gas monetization development project which reduced 2017 DD&A expense by $37 million;in second quarter 2017; and
lower sales volumes in the Gulf of Mexico due toresulting from natural field decline and reduction in the depletable costs due to downward revisions in estimates of asset retirementARO costs;
partially offset by:
higher US onshore sales volumes of 29 MBoe/d, during 2017, including 7 MBoe/d contributed by recently acquired Clayton Williams Energy assets;
an increase in sales volumes from the Gunflint development, Gulf of Mexico, which commenced production in July 2016; and
higher gross sales volumes from the Tamar field offshore Israel, due to higher domestic demand.
The unit rate per BOE for 2017 decreased 9% as compared with 2016, primarily due to year-end reserve additions in US onshore, a reduction in the Alen field net book value in second quarter 2017, and certain DJ Basin property divestitures since second quarter 2016.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/increases in the following:fair values of our crude oil and natural gas commodity derivative contracts.
For 2018, gain on commodity derivative instruments included:
net cash settlement payment of $161 million; and
net non-cash increase of $178$224 million related to higher sales volumes resulting from commencement of production from the Big Bend, Dantzler and Gunflint development projects in the Gulffair value of Mexicoour net commodity derivative asset, primarily driven by decreases in 2016the forward commodity price curve for crude oil.
For 2017, gain on commodity derivative instruments included:
net cash settlement receipt of $13 million; and 2015;
net non-cash increase of $134$50 million related toin the acquisitionfair value of Eagle Ford Shale and Delaware Basin productionour net commodity derivative liability, primarily driven by changes in third quarter 2015; and
$121 million related to the reduction in proved reserves in fourth quarter 2015, primarily due to downward price revisions in DJ Basin and Marcellus Shale;
partially offset by:
an overall lower segment rate for offshore Equatorial Guinea due to the fluctuation in production from higher DD&A rate assets, the Aseng and Alen fields, to a lower DD&A rate asset, the Alba field.
The unit rate per BOE for 2016 decreased as compared with 2015, primarily due to lower-cost production volumes from the Tamar and Alba fields and net book value impairments in fourth quarter 2015 related to downwardforward commodity price revisions. Thecurves 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 unit rate per BOE was partially offsetfair value of our net commodity derivative liability, primarily driven by increased higher-cost production volumes from certain US onshore propertieschanges in the forward commodity price curves for both crude oil and recently commenced production from Gulf of Mexico assets, including Big Bend, Dantzlernatural gas.
RESULTS OF OPERATIONS – MIDSTREAM
The Midstream segment develops, owns, operates develops and acquires domestic midstream infrastructure assets, or invests in other midstream entities, with current focus areas being the DJ and Delaware Basins.
Major Midstream Activities - Noble Midstream Partners During 2017, major activities included the following:
progressed the construction and development of multiple major projects in the DJ and Delaware Basins;
began providing crude oil and produced water gathering services to an unaffiliated third party;
entered into the Advantage Joint Venture; and
entered into the Black Diamond Gathering arrangement with definitive agreements to acquire the Saddle Butte system.
Major Midstream Activities - Noble Energy During 2017, we entered into an agreement to sell our 50% interest in CONE Gathering. We closed the sale in January 2018, receiving cash proceeds of $308 million.
Results of Operations
Highlights for the Midstream segment were as follows:
20172018 Significant Midstream Operating Highlights Included:
completed the Saddle Butte Acquisition;
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 system in the Delaware Basin, for which definitive agreements with Salt Creek were executed in February 2019;
commenced natural gas compression in the Delaware Basin; and
in first quarter 2019, exercised options to acquire equity interests in the EPIC Y-Grade Pipeline and the EPIC Crude Oil Pipeline.
2018 Midstream Financial Results Included:
pre-tax income of $233$726 million, as compared with pre-tax income of $176$233 million for 2016;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 compared with capital expenditures of $42 million for 2016.2017.
Following is a summarized statement of operations for the Midstream segment: | | | | Year Ended December 31, | Year Ended December 31, |
| (millions) | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
| Midstream Services Revenues – Third Party | $ | 19 |
| | $ | — |
| | $ | — |
| $ | 78 |
| | $ | 19 |
| | $ | — |
|
| Sales of Purchased Oil | | 142 |
| | — |
| | — |
|
| Income from Equity Method Investees | 57 |
| | 52 |
| | 51 |
| 40 |
| | 57 |
| | 52 |
|
| Intersegment Revenues | 277 |
| | 200 |
| | 119 |
| 351 |
| | 277 |
| | 200 |
|
| Total Revenues | 353 |
| | 252 |
| | 170 |
| 611 |
| | 353 |
| | 252 |
|
| Gathering, Transportation and Processing Expense | 70 |
| | 44 |
| | 25 |
| |
| Operating Costs and Expenses | | 128 |
| | 90 |
| | 57 |
|
| Depreciation, Depletion and Amortization | 30 |
| | 19 |
| | 14 |
| 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 | 233 |
| | 176 |
| | 123 |
| 726 |
| | 233 |
| | 176 |
|
Midstream Services and Intersegment
Revenues The amount of revenue generated by the Midstream businesssegment depends primarily on the volumes of crude oil, natural gas and water for which services are provided to our E&P business and to third partythird-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 and NGLs in the markets served directly or indirectly by our midstream assets.
Total revenues excluding incomefor 2018 increased from equity method investees,2017 primarily 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 by $96 million mainlyprimarily due to increases of $60 million and $17 million driven by our drilling and completion activities in the DJ and Delaware Basins, respectively, and an increase of $19 million primarily due to commencement of services in the DJ Basin to an unaffiliated third party.third-party.
Total revenues, excluding income from equity method investees, for 2016 increased from 2015 by $81 million due to our drilling and completion activities in the DJ Basin.
Income from Equity Method Investees and OtherMidstream's share of operations of equity method investees was as follows: |
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| Net Income (in millions) | | | | | | |
| CONE Gathering and CONE Midstream | | $ | 51 |
| | $ | 48 |
| | $ | 46 |
|
| Advantage Pipeline | | 2 |
| | — |
| | — |
|
| White Cliffs | | 4 |
| | 5 |
| | — |
|
| Dividends (in millions) | | | | | | |
| CONE Gathering and CONE Midstream | | 25 |
| | 27 |
| | 17 |
|
|
| | | | | | | | | | | | |
| | | 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 |
| | — |
| | — |
|
Operating Costs and Expenses
Gathering, TransportationTotal 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 Expenseprocessing 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 $26$33 million as compared with 2016 due to the following:
an increase of $20 million in water services expense due to increased services provided by third parties as well as higher throughput volumes associated with fresh water services; and
an increase of $6 million in gathering and facilities operating expense due to higher gathered volumes, as well as due to new systems placed in service and expansion of the gathering infrastructure in 2017.
Total expense for 2016 increased by $19 million as compared with 2015 due to the following:
an increase of $12 million in water services expense due to an expanded scope of water services delivered;2017; and
an
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 systemssystem in the DJ Basin, and facilities operating expense associated with higher gathered volumes as well as general repairs and maintenancean increase of our gathering systems and facilities.$30 million related to amortization of customer-related intangible assets acquired in the Saddle Butte Acquisition.
DD&A Expense
Depreciation. depletion and amortization 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 $5 million as compared with 2015 due to assets placed in service as a resultcombination of the expansion of Wells Ranch CGF in 2016 and in second half 2015 and commissioning of the East Ponyin-field crude oil gathering system during 2016.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
GeneralOur Corporate costs include exit and Administrative Expense Generalcertain 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 expense (G&A) wasexpenses.
Marcellus Shale Firm Transportation Contracts Revenues and expenses associated with retained Marcellus Shale firm transportation contracts were as follows:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| G&A Expense (millions) | $ | 415 |
| | $ | 399 |
| | $ | 396 |
|
Unit Rate per BOE (1) | $ | 3.05 |
| | $ | 2.64 |
| | $ | 3.11 |
|
|
| | | | | | | | | | | |
| | 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 Expense General and administrative (G&A) expense was as follows: |
| | | | | | | | | | | |
| | Year Ended December 31, |
| (millions, except unit rate) | 2018 | | 2017 | | 2016 |
| G&A Expense | $ | 385 |
| | $ | 415 |
| | $ | 399 |
|
Unit Rate per BOE (1) | $ | 3.05 |
| | $ | 3.05 |
| | $ | 2.64 |
|
| |
(1) | Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees. |
On a gross basis, G&A expense for 2018 increased as compared with 2017 primarily due to increased employee overhead related costs 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. The increase in the unit rate per BOE for 2017 as compared with 2016 was due primarily to the decrease in total sales volumes driven by the divestiture of the Marcellus Shale upstream assets. Our total number of employees increased from 2,274 at December 31, 2016 to 2,277 at December 31, 2017.
G&A expense for 2016 was flat as compared with 2015 primarily due to sustained cost savings initiatives and decreases in employee personnel costs. Our total number of employees decreased from 2,395 at December 31, 2015 to 2,274 at December 31, 2016.
G&A expense is impacted by the number of stock-based awards, the market price of our common stock and price volatility which may result in a higher or lower fair value of stock-based awards as calculated using various valuation models. G&A expense included stock-based compensation expense of $54 million in 2018, $56 million in 2017 and $62 million in 2016 and $50 million in 2015.2016. See Item 8. Financial Statements and Supplementary Data – Note 12.17. 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 per unit) | | 2017 | | 2016 | | 2015 | |
| (millions, except unit rate) | | 2018 | | 2017 | | 2016 |
| Interest Expense | | $ | 403 |
| | $ | 412 |
| | $ | 407 |
| $ | 355 |
| | $ | 403 |
| | $ | 412 |
|
| Capitalized Interest | | (49 | ) | | (84 | ) | | (144 | ) | (73 | ) | | (49 | ) | | (84 | ) |
| Interest Expense, Net | | $ | 354 |
| | $ | 328 |
| | $ | 263 |
| $ | 282 |
| | $ | 354 |
| | $ | 328 |
|
Unit Rate per BOE (1) | | $ | 2.60 |
| | $ | 2.17 |
| | $ | 2.07 |
| $ | 2.23 |
| | $ | 2.60 |
| | $ | 2.17 |
|
| |
(1) | Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees. |
TheInterest expense for 2018 decreased 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
isprimarily 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 (Term Loan Facility) and refinancing of our 8.25% senior notes. See Liquidity and Capital Resources - Capital Structure/Financing Strategy.2019. The decrease in capitalizedCapitalized interest infor 2017 decreased as compared with 2016 is primarily due to the write off of discoveries offshore Equatorial Guinea, lower work in progress amounts related to major long-term projects, including Gunflint, Gulf of Mexico, and the Alba B3 compression project, offshore Equatorial Guinea, partially offset by a higher work in progress amount related to the Leviathan major long-term development project, offshore Israel.project.
The increase in interest expense in 2016 as compared with 2015 is primarily due to the impact of senior notes assumed in the Rosetta Merger during third quarter 2015, a portion of which were subsequently tendered during first quarter 2016 through proceeds derived from our Term Loan Facility.
The decrease in capitalized interest in 2016 as compared with 2015 is primarily due to lower work in progress amounts related to major long-term projects, including Big Bend and Dantzler, Gulf of Mexico, which were completed in fourth quarter 2015, and Gunflint, Gulf of Mexico, and the Alba B3 compression project, offshore Equatorial Guinea, which were completed in July 2016. Additional items that contributed to the decrease in capitalized interest include the farm-out of a portion of Block 12, offshore Cyprus, during fourth quarter 2015, the write-off of the Humpback dry hole, offshore Falkland Islands, during fourth quarter 2015 and timing of US onshore activities.
Interest is capitalized on exploration and development projects using an interest rate equivalent to the average rate paid on long-term debt. Capitalized interest is included in the cost of oil and gas assets and amortized with other costs on a unit-of-production basis. The majority of the capitalized interest is related to long lead-time projects in the Gulf of Mexico, offshore
LIQUIDITY AND CAPITAL RESOURCES
Capital Structure/Financing Strategy
In seeking to effectively fund and monetize our discovered hydrocarbons, we employ a capital structure and financing strategy designed to provide sufficient liquidity throughout the commodity price cycle,cycles, including a sustained period of low prices. Specifically, we strive to retain the ability to fund long cycle, multi-year, capital intensive development projects throughout a range of scenarios, while also funding a continuing exploration program and maintaining capacity to capitalize on financially attractive periodic mergersmerger and acquisitions opportunities, such as the recent Clayton Williams Energy Acquisition.acquisition opportunities. We endeavor to maintain a strong balance sheet and an investment grade creditdebt rating in service of these objectives.
We strive to maintain a minimum liquidity level to address volatility and risk. Traditional sources of our liquidity are cash flows from operations, cash on hand, proceeds from divestitures of properties and other investments, and available borrowing capacity under our $4.0 billion unsecured Revolving Credit Facility, and proceeds from divestitures of properties. Facility. We occasionally access the capital markets to ensure adequate liquidity exists in the form of unutilized capacity under our Revolving Credit Facility or to refinance scheduled debt
During 2017, we focused on implementationcommodity 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 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 executedother US onshore assets. As a number ofresult, our divestitures which generated cash proceeds of over $2 billion. We utilized the proceeds from divestituresapproximately $2.0 billion and $2.1 billion in 2018 and 2017, respectively, which were used to improve our capital structure, by repaymentfund a portion of $1.3 billion of borrowing under our Revolving Credit Facility associated with the Clayton Williams Energy Acquisition and $550 million of the remaining balance outstanding under our Term Loan Facility due January 6, 2019. To furthercapital program, strengthen our liquidity profileand return value to shareholders through the share repurchase program.
In 2018, we performed a series of financing transactions, including retirement of $1 billion of our 8.25% senior notes due March 1, 2019 with the proceeds from issuance of $600 million of 3.85% and $500 million of 4.95% senior notes due January 15, 2028 and August 15, 2047, respectively. Through the repayment of our Term Loan Facility and refinancing of our 8.25% senior notes, we effectively eliminated our near-term debt maturities and lowered our future interest expense by $48 million on an annual basis.
We aim to fundfunded our capital program through operatingorganic cash flows, proceeds from divestitures and, utilizewhen needed, borrowings under our Revolving Credit Facility to fund additional requirements. In 2017,Facility. During the year, we borrowed and repaid amounts under our Revolving Credit Facility, resulting in $230 million remainingno amounts outstanding as of December 31, 2017. Funds were utilized for general corporate purposes and for funding of our capital development program.2018. As a result of our 2017 financing activities, we ended 20172018 with over $4.5$4.7 billion in liquidity, including almost $3.8$4.0 billion of availability under our Revolving Credit Facility.
During 2017, we also focused on the continued execution of our integrated midstream strategy through Noble Midstream Partners. In addition to completion of several key infrastructure assets in the DJ and Delaware Basins, as well as continuing significant construction activities in the DJ Basin, Noble Midstream Partners purchased certain midstream assets from Noble Energy for $270 million and expanded its business through entry into certain arrangements to acquire and operate midstream assets. Funding for these transactions included $312 million raised through the issuance of Noble Midstream Partners common units and borrowings under the Noble Midstream Services LLC Revolving Credit Facility (Noble Midstream Services Revolving Credit Facility). As of December 31, 2017, $85 million was outstanding under the Noble Midstream Services Revolving Credit Facility. Funds were used to partially fund 2017 acquisitions and to finance the midstream capital investment program. See Item 8. Financial Statements and Supplementary Data - Note 4. Acquisitions, Divestitures and Merger.In addition, we received $300 million in payments from foreign operations on an outstanding note payable in 2017, leaving a balance of approximately $434 million that can be repaid without additional US tax impact.
As of December 31, 2017,2018, our outstanding long-term debt, (excludingnet of unamortized discount and debt issuance costs and excluding capital lease and other obligations)obligations, totaled $6.5$6.4 billion. While we have no near-term debt maturities, weWe may periodically seek to access the capital markets to refinance a portion of our outstanding indebtedness.
We In addition, we may from time to time seek to retire or purchase our outstanding senior notes and/or seek to improve shareholder returns, through cash purchases in the open market, privately negotiated transactions or otherwise. Such activities, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
Sources and Uses of Liquidity
Our operating cash flows are a significant source of our liquidity. In 2017,For most of 2018, we experienced strengthening crude oil and NGL prices and completed several transformative transactions,divestitures which continued the transformation strategy started in 2017, repositioning our US portfolio from low-margin natural gas-focused assets to high margin onshore crude oil-rich assets, whichassets. 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,Facility. At the same time, we focused efforts on shareholder return initiatives, including share repurchases and divestmentdividends. Additionally, we redeemed $379 million in outstanding senior notes and repaid $230 million of certain non-strategic oil and gas properties. Duringoutstanding 2017 we continued investment inborrowings on our high cash flow growth assets and, excluding effects of divestitures, increased production levels from prior years, while also increasing per unit profit margins. We also improved our financial profile by reducing our debt balance by $255 million with the use of proceeds from divestments, and decreasing our future interest expense.Revolving Credit Facility.
For 2018,Overall, we will continue our effort to manage our cash flows through capital efficiencies, cost management endeavors, and focusing on the growth of production from high-margin, high-return assets. With such an approach, nearly all of our 2018 capital investment is allocated to our US onshore plays and the Eastern Mediterranean, specifically the Leviathan development project, offshore Israel.
Our 2018 production target is in the range of 343 MBoe/d to 353 MBoe/d and we expect our 2018 capital spending program (excluding acquisitions and Noble Midstream Partners capital), to be in the range of $2.7 to $2.9 billion, or approximately $400 million higher than the 2017 budget. Should WTI and Brent oil prices continue to improve in 2018, we expect future operating cash flows to increase and provide additional sources of liquidity compared to 2017. We expect to support our 2019 capital investment program with operating cash flows resulting from our US onshore and Israel offshore assets, with the remainder of the future capital commitments funded withoperations, cash on hand, proceeds from divestments of non-strategic assets, issuances of commercial paper, borrowings under our Revolving Credit Facility, and divestmentand/or other sources of non-strategic assets.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 2018. However, a2019. A downgrade or other negative action with respect tobelow our creditcurrent investment grade rating could trigger requirements to post collateral as financial assurance of performance under certain contractual arrangements, potentially impacting our liquidity and/or negatively impacting our cost, terms, conditions and availability of future financing.arrangements. See Item 1A. Risk Factors – A downgrade or other negative action with respect toIndebtedness may limit our credit rating could negatively impact our businessliquidity and financial condition.flexibility. The table below summarizes our cash, debt balances and available liquidity: | | | | December 31, | | | | | | | |
| | 2017 | | 2016 | | 2015 | December 31, |
| (millions, except percentages) | | | | | |
| 2018 | | 2017 | | 2016 |
Total Cash (1) | $ | 713 |
| | $ | 1,209 |
| | $ | 1,028 |
| $ | 719 |
| | $ | 713 |
| | $ | 1,210 |
|
Amount Available to be Borrowed Under Revolving Credit Facility (2) | 3,770 |
| | 4,000 |
| | 4,000 |
| |
Amount Available to be Borrowed under Revolving Credit Facility (2) | | 4,000 |
| | 3,770 |
| | 4,000 |
|
| Total Liquidity | $ | 4,483 |
| | $ | 5,209 |
| | $ | 5,028 |
| $ | 4,719 |
| | $ | 4,483 |
| | $ | 5,210 |
|
Total Debt (3) | $ | 6,859 |
| | $ | 7,114 |
| | $ | 7,976 |
| $ | 6,675 |
| | $ | 6,859 |
| | $ | 7,114 |
|
| Noble Energy Share of Equity | 10,619 |
| | 9,600 |
| | 10,370 |
| 10,484 |
| | 10,619 |
| | 9,600 |
|
Ratio of Debt-to-Book Capital (4) | 39 | % | | 43 | % | | 43 | % | 39 | % | | 39 | % | | 43 | % |
| |
(1) | TotalAs of December 31, 2018, total cash atincludes 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 of December 31, 2017, total cash includes $18 million cash of Noble Midstream Partners and $37.5$38 million of restricted cash related to the Saddle Butte acquisitionAcquisition that closed in first quarter of 2018. Total cash atAs 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. |
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(2) | In 2017, amount available to be borrowed under the Revolving Credit Facility excludes $265 million and $625 millionExcludes amounts available to be borrowed under the Noble Midstream Services Revolving Credit Facility, and Leviathan Term Loan Facility (defined below), respectively, which areis not available to Noble Energy for general corporate purposes. In 2016, it excludes $350 million available to be borrowed under the Noble Midstream Services Revolving Credit Facility. See discussion below. |
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(3) | Total debt includes capital lease and other 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. |
Our long-term debt (excluding capital lease and other obligations) totaled $6.5 billion at December 31, 2017, with maturities ranging from 2020 to 2097.
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(4) | We define our ratio of debt-to-book capital as total debt (which includes long-term debt excluding unamortized discount/premium and issuance costs, the current portion of long-term debt, and short-term borrowings) divided by the sum of total debt plus Noble Energy's share of equity.Significant changes in our financial position impacting the ratio included $255 million net decrease in debt, $1.9 billion increase in shareholders' equity due to issuance of stock as part of consideration paid for Clayton Williams Energy Acquisition, $312 million increase due to issuance of Noble Midstream Partners Common Units and $100 million increase due to stock based compensation, offset by $190 million decrease in shareholders' equity from dividends paid and $1.1 billion decrease in shareholders' equity from current year net loss. |
Cash and Cash Equivalents Our We had approximately $716 million in cash isand 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 $493$456 million of this cash wasis attributable to our foreign subsidiaries at December 31, 2017.subsidiaries. We do not expect to incur any significant US income tax expense with respect to future repatriation of foreign cash.
Revolving Credit FacilitiesNoble Energy's Revolving Credit Facility of $4.0 billion matures in 2020. Theand the Noble Midstream Services Revolving Credit Facility of $350$800 million maturesboth mature in 2021.2023. These facilities are used to fund capital investment programs and acquisitions and may periodically provide amounts for working capital purposes. At December 31, 2017, $230 million was2018, no amounts were outstanding under the Revolving Credit Facility and $85$60 million was outstanding under the Noble Midstream Services Revolving Credit Facility, leaving leaving$3.84.0 billion and $265740 million in remaining availability under the respective credit facilities. See Item 8. Financial Statements and Supplementary Data -– Note 10.9. Long-Term Debt. Commercial Paper Program In 2019, we established a commercial paper program, which allows for a maximum of $4.0 billion of unsecured commercial paper notes and is supported by Noble Energy’s Revolving Credit Facility, to provide for short-term funding needs. Commercial paper generally has a maturity of between 1 and 90 days, although it can have a maturity of up to 397 days. The commercial paper is sold under customary terms in the commercial paper market and notes either are issued at a discount price to their principal face value or will bear interest at varying interest rates on a fixed or floating basis. Such discounted prices or interest amounts are dependent on market conditions and ratings assigned to the commercial paper program by the credit agencies at the time of issuance of the commercial paper.
Noble Midstream Services Term Loan Credit Facility In July 2018, Noble Midstream Services entered into the Noble Midstream Services Term Loan Credit Facility that permits aggregate borrowings of up to $500 million. As of December 31, 2018, $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. Long-Term Debt. Leviathan Term Loan Facility On February 24, 2017, we entered into aThe facility, agreement (Leviathan Term Loan Facility) providingwhich provided for a limited recourse secured term loan facility with an aggregate principal borrowing amount of up to $1$1.0 billion, of which $625 million iswas initially committed. Any amounts borrowed under the Leviathan Term Loan Facility will be available to fund a portion of our share of costs for the initial phase of development of the Leviathan field, offshore Israel. To support the Leviathan development program and to bring first production online by the end of 2019, we may borrow amounts under this facilitycommitted, was terminated in the near-term. As of December 31, 2017, no2018. No amounts were ever drawn underon this facility.
Term Loan FacilityLegacy Rosetta Note Redemption In fourth quarter 2017,May 2018, we utilized proceeds received from saleredeemed $379 million of non-strategic acreage in the DJ Basin to repay the remaining outstanding balance of $550 million under this $1.4 billion facility. See Item 8. Financial Statements and Supplementary Data - Note 10. Long-Term Debt.Senior Notes During 2017due May 1, 2021, that we took stepshad assumed in managing our long-term debt maturities and liquidity through a seriesacquisition of financing transactions. We issued $600 million of 3.85% senior unsecured notes that will mature on January 15, 2028 and $500 million of 4.95% senior unsecured notes that will mature on August 15, 2047. We used the proceeds to redeem $1 billion of our 8.25% senior unsecured notes which were due March 1, 2019. Through these transactions, we effectively enhanced our financial flexibility and lowered our future cash interest expense by approximately $35 million on an annual basis. See Item 8. Financial Statements and Supplementary Data - Note 10. Long-Term Debt.Rosetta Resources, for $395 million. Cash Flows
The following table summarizes our net cash flows from operating, investing and financing activities: | | | | | Year Ended December 31, | | | | | | | |
| | | 2017 | | 2016 | | 2015 | | Year Ended December 31, |
| (millions) | | | | | | | | 2018 | | 2017 | | 2016 |
| Total Cash Provided By (Used in) | | | | | | | | | | | | |
| Operating Activities | | $ | 1,951 |
| | $ | 1,351 |
| | $ | 2,062 |
| | $ | 2,336 |
| | $ | 1,951 |
| | $ | 1,351 |
|
| Investing Activities | | (1,606 | ) | | (431 | ) | | (2,871 | ) | | (1,931 | ) | | (1,617 | ) | | (401 | ) |
| Financing Activities | | (850 | ) | | (768 | ) | | 654 |
| | (399 | ) | | (831 | ) | | (768 | ) |
| Increase (Decrease) in Cash and Cash Equivalents | | $ | (505 | ) | | $ | 152 |
| | $ | (155 | ) | |
| Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash | | | $ | 6 |
| | $ | (497 | ) | | $ | 182 |
|
Operating Activities Cash flows fromIn 2018, net cash provided by operating activities include all transactionsincreased as compared with 2017, primarily resulting from an increase in net revenues due to rising crude oil and other events that are not definedNGL commodity prices, partially offset by higher production costs attributable to increased operational activity and rising costs in US onshore, and a decrease in US natural gas sales volumes. In addition, we made cash settlements of $161 million for commodity derivatives, as investing or financing activitiescompared with cash receipts of $13 million in the prior year and are generallycash interest payments related to outstanding debt of $343 million as compared with $394 million in 2017.
Working capital changes resulted in a $47 million operating cash flow decrease in 2018 as compared with a $150 million operating cash flow decrease in 2017. The changes in working capital 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 cash effectsincrease in non-current assets, specifically the customer-related intangible asset recorded as part of transactions and other events that enter into the determinationSaddle Butte Acquisition in first quarter 2018.
In 2017, net cash provided by operating activities increased as compared with 2016. The change in cash flows from operating activities was primarily the result of higher average realized commodity prices partially offset by lower sales volumes as a result of the Marcellus Shale upstream divestiture and lower settlements of commodity derivative instruments. The reduction of our sales volumes was mainly driven by the decrease in sale of natural gas as a result of Marcellus Shale upstream asset divestiture. The increase in cash flows from sales was offset by the decrease in settlementssettlement proceeds from our commodity derivative instruments. The decrease in cash received from derivative settlements is reflective of an increase in the commodity prices as crude oil and natural gas prices strengthened in the second half of 2017.
Working capital changes resulted in a $150 million operating cash flow decrease in 2017 as compared with a $460 million operating cash flow decrease in 2016. The changes in working capital were primarily due to an increase in our current liabilities, including accrued liabilities and trade payables for drilling and development costs and midstream capital expenditures. The increase in current liabilities was partially offset by the increase in accounts receivable resulting from higher revenues and higher joint interest billing receivables, primarily due to billings associated with Leviathan development project costs.
In 2017, we made cash interest payments related to outstanding debt of $394 million as compared towith $412 million in 2016.
In 2016, net cash provided by operating activities for 2016 decreased as compared with 2015. Decreases in average realized commodity prices and lower settlements of commodity derivative instruments were partially offset by increases in sales volumes. Working capital changes resulted in a $460 million operating cash flow reduction in 2016 as compared with a negative impact of $129 million in 2015 and were due primarily to decreases in capital accruals related to reduced development activity, as well as an increase in accounts receivable related to higher revenues.
In 2016, we made cash interest payments related to outstanding debt of $412 million as compared to $404 million in 2015.
Investing Activities Our investing activities include capital spending on a cash basis for oil and gas properties and midstream infrastructure and investments in unconsolidated subsidiaries accounted for by the equity method. These investing activities may be offset by proceeds from property sales or dispositions, including farm-out arrangements, which may result in reimbursement for capital spending that had occurred in prior periods.
In 2017,2018, capital spending for additions to property, plant and equipment, excluding acquisitions, totaled $3.3 billion as compared with $2.6 billion comparedin 2017. The increase was primarily due to $1.5increased 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.
During 2018, we received net cash proceeds of $2.0 billion from divestitures. We utilized sales proceeds to support our development activities in core operational areas, redeem senior note balances and further strengthen our liquidity position. See Item 8. Financial Statements and Supplementary Data – Note 5. Acquisitions and Divestitures. 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 addition, we used $637 million of cash, net of $21 million of cash acquired, to fund a portion of the consideration paid in the Clayton Williams Energy Acquisition,2016, capital spending for property, plant and we acquired Delaware Basin and other assets for $327 million.
In 2017, we received net cash proceeds of over $2 billion from divestitures of non-core assets, including:
$1.0 billion from the Marcellus Shale upstream divestiture;
$568 million on the sale of Greeley Crescent and Bronco acreage in the DJ Basin; and
$335 million from the sale of mineral and royalty assets.
We utilized these sales proceeds to partially fund our Clayton Williams Energy Acquisition, support our development activities in core operational areas, repay outstanding balances under the Term Loan Facility and further strengthen our liquidity position.
Other investing activities provided a net $87 million of cash as of December 31, 2017.
In comparison, capital expenditures in 2016 wereequipment 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 approximately $1.2 billion of proceeds from asset divestitures, during 2016 as compared with $151 million of proceeds from divestitures during 2015.
Financing ActivitiesIn 2016, we invested $82018, our primary financing activities included a $230 million, net, Revolving Credit Facility repayment and a $25 million, net, Noble Midstream Services Revolving Credit Facility repayment, which included borrowings of $475 million primarily used to fund an acquisition, offset by a repayment of $500 million drawn under the Noble Midstream Services Term Loan Credit Facility. We also used $384 million of cash to redeem senior notes, for which payment of accrued interest of $11 million is reflected in CONE Gathering, and received cash distributions of $70 million, accounted for as investing activity, from CONE Midstream.operating activities.
In 2015, capital spending for property, plant and equipment was $3.0 billion, representing a decrease of $1.9 billion as compared with 2014, primarily due to decreased major project development activity in our operational areas. We received $151 million of proceeds from asset divestitures during 2015 as compared with $321 million proceeds from divestitures during 2014, and acquiredaddition, we used cash of $61$295 million in the Rosetta Merger. We also invested $104pursuant to our share repurchase program and paid $208 million in CONE Gathering in 2015.
Financing ActivitiesOur financing activities include the issuance or repurchase of Noble Energy common stock and Noble Midstream Partners common units, payment of cash dividends to Noble Energy shareholders and $51 million of cash distributions to Noble Midstream Partners noncontrolling interest owners, and debt transactions.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 from the issuance of Noble Midstream Partners common units, paid $190 million of cash dividends and $28 million of cash distributions, and made $60 million of capital lease principal payments.
We also received $10 million cash proceeds from the exercise of stock options and purchased 1,031,000 shares of treasury stock with a value of $36 million. These shares included 719,849 shares with a value of $25 million related to vesting of Clayton Williams Energy restricted stock and options in connection with the Clayton Williams Energy Acquisition. The remaining shares were surrendered for the payment of withholding taxes due on the vesting of employee restricted stock awards.
In 2016, we used Term Loan Facility proceeds of $1.4 billion to redeem $1.4 billion of senior notes. We subsequently repaid $850 million of the Term Loan Facility from cash on hand. We received $299 million net proceeds from the issuance of Noble Midstream Partners common units in a public offering. Funds wereWe also provided by cash proceeds from, and tax benefits
In 2015, we received approximately $1.1 billion net proceeds from the issuance of shares of common stock in a public offering. Funds were also provided by cash proceeds from, and tax benefits related to, the exercise of stock options ($7 million). We used cash to pay dividends on our common stock ($291 million), make principal payments related to capital lease obligations ($67 million), and repurchase 491,000 shares of our common stock ($21 million). Subsequent to the Rosetta Merger, we incurred financing cash outflows to facilitate the exchange of Rosetta's debt ($12 million) as well as repay the balance outstanding under Rosetta's credit facility ($70 million).
DividendsWe paid cash dividends totaling 40 cents per common share in 2017, 40 cents per common share in 2016, and 72 cents per common share in 2015. See
Acquisition, Capital Expenditures and Other Exploration Expenditures
Our capital expenditures (on an accrual basis) were as follows for the year ended December 31, 2017:follows: | | | | | Year Ended December 31, | | | | | | | |
| | | 2017 | | 2016 | | 2015 | | Year Ended December 31, |
| (millions) | | | | | | | | 2018 | | 2017 | | 2016 |
| Acquisition, Capital and Exploration Expenditures | | |
| | |
| | | | |
| | |
| | |
Unproved Property Acquisition (1) | | $ | 1,817 |
| | $ | 234 |
| | $ | 1,480 |
| | $ | 41 |
| | $ | 1,817 |
| | $ | 234 |
|
Proved Property Acquisition (2) | | 839 |
| | — |
| | 1,613 |
| | — |
| | 839 |
| | — |
|
| Exploration | | 42 |
| | 222 |
| | 322 |
| |
| Development | | 2,310 |
| | 1,017 |
| | 2,055 |
| |
| Exploration and Development | | | 2,683 |
| | 2,352 |
| | 1,239 |
|
Midstream(3) | | 480 |
| | 42 |
| | 356 |
| | 727 |
| | 480 |
| | 42 |
|
| Corporate and Other | | 34 |
| | 50 |
| | 97 |
| |
| Corporate | | | 60 |
| | 34 |
| | 50 |
|
| Total | | $ | 5,522 |
| | $ | 1,565 |
| | $ | 5,923 |
| | $ | 3,511 |
| | $ | 5,522 |
| | $ | 1,565 |
|
| Other | | |
| | | | |
| | |
| | | | |
|
Investment in Equity Method Investee (4) | | $ | 68 |
| | $ | 8 |
| | $ | 104 |
| | $ | — |
| | $ | 68 |
| | $ | 8 |
|
Increase in Capital Lease Obligations (5) | | — |
| | 5 |
| | 55 |
| |
| Increase in Capital Lease Obligations | | | 14 |
| | — |
| | 5 |
|
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(1) | 20172018 costs include $1.6 billion relatedrelate to the Clayton Williams Energy Acquisition and $246 million related to the Delaware Basin asset acquisition.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 with CONSOL upon termination of the Marcellus Shale joint development agreement.
2015 costs include $1.4 billion related to the Rosetta Merger.
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(2) | 2017 costs include $722 million of proved properties and $63 million of asset retirement obligationsARO acquired in the Clayton Williams Energy Acquisition and $58 million related toof proved properties acquired in the Delaware Basin asset acquisition.Basin. |
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(3) | Midstream expenditures include those of Noble Midstream Partners. |
2015 costs of $1.6 billion are2018 includes $206 million related to the Rosetta Merger.Saddle Butte Acquisition.
2017 includes gathering and processing assets of $48 million related to the Clayton Williams Energy Acquisition.
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(3)
| 2017 includes gathering and processing assets of $48 million related to the Clayton Williams Energy Acquisition. |
2016 includes Noble Midstream Partners expenditures.
2015 includes midstream assets acquired in the Rosetta Merger.
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(4) | 2017 includes our contribution to the Advantage Joint Venture,Pipeline joint venture, in which Noble Midstream Partners owns a 50% interest. |
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(5)
| Relates to US onshore assets. |
Total capital expenditures increased during 20172018 as compared with 2016 as we pursued strategic portfolio repositioning through a number of acquisitions in our core2017, primarily due to increased US onshore operational areas in the Delaware Basin and also continued execution of our midstream capital investment program through Noble Midstream Partners. The increase inLeviathan development capital is in response to the strengthening of commodity prices in the second half of 2017activities. Exploration and isdevelopment costs include approximately $2.0 billion for US onshore and approximately $676 million for Eastern Mediterranean activities primarily related to drilling and development costsLeviathan. In addition, Midstream capital spending, exclusive of $1.9 billion incurred mainlyacquisitions, increased in our three US onshore plays (DJ Basin, Delaware Basin and Eagle Ford Shale). Additionally, $416 million of capital expenditures in 2017 was associated with the initial Leviathan project development, while in 2016 we incurred $106 million of project development costs, offshore Israel.
In 2016, total expenditures decreased as compared with 2015, excluding acquisition costs of $3.2 billion related2018 due to the Rosetta Merger, as we responded toconstruction of gathering systems in the lower commodity price environment.
2015 expenditures, excluding the Rosetta Merger, reflect our reduced capital spending program. Given the 2015 commodity price environmentDJ and an industry cost structure that had yet to fully reset to lower revenue levels, we designed a substantially reduced capital investment program that was appropriate for the price environment.Delaware Basins.
Off-Balance Sheet Arrangements
We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2017,2018, material off-balance sheet arrangements and transactions that we have entered into included drilling rig contracts, transportation and gathering agreements, operating lease agreements, and undrawn letters of credit, all of which are customary in the oil and gas industry (see cross references to the Notes to the Financial Statements in the table below). Other than these aforementioned arrangements, we have no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our financial condition, results of operations, liquidity or availability of or requirements for capital resources. See also Contractual Obligations, below.
Contractual Obligations
The following table summarizes certain contractual obligations as of December 31, 20172018 that are reflected in the consolidated balance sheets and/or disclosed in the accompanying notes. Unless otherwise noted, all amounts shownare undiscounted and are net to our interest.
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Obligation | Note
Reference (1) | Total | | 2018 | | 2019 and 2020 | | 2021 and 2022 | | 2023 and beyond |
| (millions) | | | | | | | | | | |
Long-Term Debt (2) | | $ | 6,586 |
| | $ | — |
| | $ | 230 |
| | $ | 1,464 |
| | $ | 4,892 |
|
Interest Payments (3) | | 5,804 |
| | 324 |
| | 645 |
| | 555 |
| | 4,280 |
|
Capital Lease and Other Obligations (4) | | 335 |
| | 74 |
| | 87 |
| | 50 |
| | 124 |
|
Drilling and Equipment Obligations (5) | | 448 |
| | 343 |
| | 105 |
| | — |
| | — |
|
Purchase Obligations (6) | | 448 |
| | 293 |
| | 101 |
| | 22 |
| | 32 |
|
Transportation and Gathering (7) | | 2,474 |
| | 215 |
| | 499 |
| | 405 |
| | 1,355 |
|
Operating Lease Obligations (8) | | 330 |
| | 44 |
| | 65 |
| | 65 |
| | 156 |
|
Other Liabilities (9) | | | | | | | | | | |
Asset Retirement Obligations (10) | | 875 |
| | 51 |
| | 267 |
| | 99 |
| | 458 |
|
Commodity Derivative Instruments (11) | | 68 |
| | 53 |
| | 15 |
| | — |
| | — |
|
| Total Contractual Obligations | | $ | 17,368 |
| | $ | 1,397 |
| | $ | 2,014 |
| | $ | 2,660 |
| | $ | 11,297 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| (millions) | Note
Reference (1) | Total | | 2019 | | 2020 and 2021 | | 2022 and 2023 | | 2024 and beyond |
Long-Term Debt (2) | | $ | 6,452 |
| | $ | — |
| | $ | 1,500 |
| | $ | 160 |
| | $ | 4,792 |
|
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 |
|
| Gathering, Transportation and Processing Obligations | | 801 |
| | 151 |
| | 232 |
| | 133 |
| | 285 |
|
Operating Lease Obligations (7) | | 512 |
| | 91 |
| | 133 |
| | 112 |
| | 176 |
|
Other Liabilities (8) | | | | | | | | | | |
Asset Retirement Obligations (9) | | 880 |
| | 118 |
| | 147 |
| | 67 |
| | 548 |
|
Commodity Derivative Instruments (10) | | 27 |
| | 1 |
| | 26 |
| | — |
| | — |
|
| Total Contractual Obligations | | $ | 16,239 |
| | $ | 1,028 |
| | $ | 2,989 |
| | $ | 1,277 |
| | $ | 10,945 |
|
| |
(2) | Long-term debt excludes capital lease obligations and includes our fixed rate debt and revolving credit facilities balances based on the maturity dates of the facilities.and fixed-rate debt and excludes unamortized discounts, premiums, debt issuance costs and capital lease obligations. |
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(3) | Interest payments are based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2017.2018. |
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(4) | Annual capital lease payments net to our interest, exclude regular maintenance and operational costs. |
| |
(5) | Drilling and equipment obligations represent our working interest share of contractual agreements with third-party service providers to procure drilling rigs and other related equipment for exploratory and development drilling activities. See Counterparty Credit Risk, above. |
| |
(6)
| Purchase and service obligations represent our working interest share of contractual agreements to purchase goods or services that are enforceable, are legally binding and specify all significant terms, including fixed and minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. See Counterparty Credit Risk, above. |
| |
(7)(6)
| 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. |
| |
(8)(7)
| Operating lease obligations represent non-cancelable leases for office buildings, and facilities and oil and gas operations equipment used in our daily operations. Amounts have not been discounted.operations, such as drilling rigs, vessels and compressors. Annual lease payments exclude regular maintenance and operational costs. |
| |
(10)(9)
| Asset retirement obligationsAROs are discounted. |
| |
(11)(10)
| Amount represents open commodity derivative instruments that were in a net payable position with the counterparty at December 31, 2017.2018. |
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 periods of several years, and failure to conduct such exploration activities within the prescribed periods could lead to loss of leases or exploration rights. Our exploration commitments currently include 3D seismic obligations for certain international locations.rights and/or penalty payments.
Continuous Development ObligationsAlthough the majority of our assets are held by production, certainCertain 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.substantial, or exercise options with land owners to extend leases. Failure to meet these obligations may result in the loss of a lease.leases.
Leviathan Natural Gas Project The initial development of the Leviathan field requires substantial infrastructure and capital. Wecapital; therefore, we have executed major equipment and installation contracts in support of developmentthese activities. As of December 31, 2017,2018, we had entered into contracts with remaining obligations of approximately $464$176 million, net, of contracts to support the remaining development activities and bring first production online by the end of 2019.
Marcellus Shale Firm Transportation AgreementsIn connection with the Marcellus Shale upstream divestiture, we reduced our firm transportation financial commitments through the transfer of several contracts to the acquirer and retained certain other firm transportation contracts representing a total financial commitment of approximately $1.4 billion, undiscounted, primarily with remaining contract terms of two to 16 years.
One of the retained contracts relates to the Texas Eastern Pipeline, a major interstate natural gas transmission pipeline delivering natural gas to the northeastern US. This contract will be fully utilized through an agreement with the acquirer, whereby the acquirer will deliver quantities of natural gas to us and receive a netback sales price that reflects the value received by us at the sales point, less our effective fixed transportation fees and other expenses, plus a margin. This contract represents an undiscounted financial commitment of approximately $114 million as of December 31, 2017, before offset by the netback agreement, thus reducing the remaining overall commitment noted above.
Two of the retained contracts relate to the Leach Xpress and Rayne Xpress projects. These are interstate natural gas transmission pipelines, which were completed and placed in service in late 2017 and early 2018 to transport production from the Marcellus Shale to markets outside the basin. In fourth quarter 2017, we permanently assigned a portion of our retained capacity to a third party and reduced our remaining undiscounted financial commitment to approximately $418 million. At this time, we are unable to predict with certainty the outcome of our commercialization activities, our ability to utilize retained capacity and the timing of when we may recognize a non-cash exit cost in line with accounting for exit costs associated with these two pipeline projects.
Two additional retained contracts relate to the NEXUS and WB Xpress projects. These projects also include interstate natural gas transmission pipelines designed to transport production from the Marcellus Shale to markets outside the basin. Both projects have received FERC approval, will undergo construction activities and are targeted for in-service late 2018. These contracts represent an undiscounted financial commitment of approximately $870 million.
We are currently engaged in actions to commercialize and address these remaining commitments, which provide for the transportation of approximately 450,000 MMBtu/d of natural gas. Actions include the permanent assignment of capacity, negotiation of capacity release, utilization of capacity through purchase of third party natural gas, and other potential arrangements. In addition, we have a “call” or right to purchase natural gas, priced at a regional index, from the acquirer of the Marcellus Shale upstream assets. This call extends through July 1, 2022 and may be exercised on quantities of the acquirer's production between 431,100 MMBtu/d and 832,645 MMBtu/d.
We expect these actions, some of which may require pipeline and/or FERC approval, to ultimately reduce the financial commitment associated with these contracts. At the date each pipeline is placed in service and our commitment begins, we will evaluate our position. If we determine that we will not utilize a portion, or all, of the contracted pipeline capacity, we will accrue a liability, at fair value, for the net amount of the estimated remaining financial commitment and include the related expense in operating expense in our consolidated statements of operations.
In accordance with US GAAP, we recognize the fair value of a liability for an exit cost in the period in which a liability is incurred. As a result, in second quarter 2017, we accrued non-cash exit costs of $41 million, discounted, relating to our transportation contract with the Appalachian Gateway Project (Gateway). Gateway, another natural gas transmission pipeline, is currently in service. We no longer have production to satisfy this commitment and do not plan to utilize this capacity in the future. In addition, we recorded a $52 million accrual, discounted, in fourth quarter 2017 relating to future commitments to the third party who assumed a portion of our capacity on the Leach Xpress and Rayne Xpress Projects. Both charges are included in loss on Marcellus Shale upstream divestiture in our consolidated statements of operations. See Item 8. Financial Statements and Supplementary Data – Note 17. Commitments and Contingencies.Other US Transportation AgreementsCertain of these contracts require us to make payments for any shortfalls in delivering or transporting minimum volumes under the commitments. As properties are undergoing development activities, we may experience temporary shortfalls until production volumes increase to meet or exceed the minimum volume commitments and will incur expense related to volume deficiencies and/or unutilized commitments. These amounts are recorded as marketing expense in our consolidated statements of operations. We expect to continue to incur expense related to deficiency and/or unutilized commitments in the near-term. Should commodity prices decline or if we are unable to continue to develop our properties as planned, or certain wells become uneconomic and are shut-in, we could incur additional shortfalls in delivering or
transporting the minimum volumes, and we could be required to make payments in the event that these commitments are not otherwise offset. We continually seek to optimize under-utilized assets through capacity release and third-party arrangements, as well as, for example, through the shifting of transportation of production from rail cars to pipelines when we receive a higher netback price. We may continue to experience these shortfalls both in the near and long-term. Item 8. Financial Statements and Supplementary Data – Note 2. Additional Financial Statement InformationOIL Contingency As of December 31, 2017,2018, we accrued approximately $19$28 million for an insurance contingency due to our membership in OIL. OIL is a mutual insurance company which insures specific property, pollution liability and other catastrophic risks. As part of our membership, we are contractually committed to pay termination fees should we elect to withdraw from OIL. We do not anticipate withdrawing from OIL; however, the potential termination fee is calculated annually based on OIL’s past losses, and the liability reflecting this potential charge has been accrued as of December 31, 2017.2018.
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 $90$89 million at December 31, 2017.2018.
Ratings TriggersWe do not have triggers on any of our corporate debt that would cause an event of default in the case of a downgrade of our credit rating. In addition, there are no existing ratings triggers in any ofSee Item 1A. Risk Factors - Indebtedness may limit our commodity hedging agreements that would require the posting of collateral. However, a series of downgrades or other negative rating actions could increase our cost of financing,liquidity and may increase our requirements to post collateral as financial assurance of performance under certain other contractual arrangements such as pipeline transportation contracts, crude oil and natural gas sales contracts, work commitments and certain abandonment obligations. A requirement to post collateral could have a negative impact on our liquidity.
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
DescriptionAll We estimate proved oil and gas reserves according to the definition of theproved reserves data in this Annual Report on Form 10-K are estimates. Estimates of our crude oil, natural gas and NGL reserves are prepared by our qualified petroleum engineers in accordance with guidelines establishedprovided by the SEC. Reservoir engineering is a subjective process with numerous uncertainties inherent in estimating underground accumulations of crude oil, natural gas and NGLs, including the projection of future production ratesSEC and the expected timing of development expenditures. In addition, economic producibility of reserves is dependent on the commodity prices used in the reserves estimate. Our reserves estimates are based on historical 12-month average commodity prices, unless contractual arrangements designate the price to be used, in accordance with SEC rules.
Financial Accounting Standards Board (FASB). Reserves estimates have a significant impact on our financial statements and disclosures, as the estimatesthey are used as an input in the calculation of our DD&A expense assessment ofand in impairment ofassessments for crude oil and natural gas properties and in preparation of Supplemental Oil and Gas Disclosures.goodwill.
Judgment and Uncertainties The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Commodity prices and development and production costs are factors used in determining reserves economics and reserves estimates. As a result, our reserves estimates will change in the future due to commodity price volatility and cost changes, as well as due to new information obtained from development drilling and production history.
Effect if Actual Results Differ from Assumptions Our reserves estimates are based on year-end cost, development, 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 and NGLs that are ultimately recovered due to reservoir performance and new geological and geophysical data. Additionally, increases in future drilling, development, production and abandonment costs and changes in commodity prices may result in future revisions to our reserves.
Estimates of proved crude oil, NGL and natural gas and NGL reserves significantly affect our DD&A expense. For example, if estimates of proved reserves decline, the DD&A rate will increase, resulting in a decrease in net income. For 2018, a 10% reduction in estimates of proved reserves across all properties would have increased DD&A expense by approximately $190 million.
A decline in estimates of proved reserves could also cause us to perform an impairment analysis to determine if the carrying amount of crude oil and natural gas
Oil and Gas Properties -– Successful Efforts Method of Accounting
Description We account for crude oil and natural gas properties under the successful efforts method of accounting. Application of the successful efforts methodaccounting 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.
Under the successful efforts method, we capitalize the following:
Acquisition costs - Costs associated with the purchase, lease or other costs to acquire mineral interests in crude oil and natural gas properties are initially capitalized as unproved property acquisition costs. These costs are commonly attributable to undeveloped leasehold costs or are derived from allocated fair values as a result of business combinations. Continued capitalization of these costs is dependent upon discovery of proved reserves. For example:
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◦ | If no proved reserves are discovered after exploration, drilling or lapse of the lease, then costs are impaired. As part of our periodic impairment review, we review undeveloped leasehold costs for potential impairment and if, based upon a change in exploration plans, timing and extent of development activities, availability of capital and suitable rig and drilling equipment, resource potential, comparative economics, changing regulations and/or other factors, an impairment is indicated, we will record impairment expense related to the respective lease. |
When we have allocated fair values to a significant unproved property (probable and/or possible reserves) as the result of a business combination or other purchase of proved and/or unproved properties, we use a future cash flows analysis to assess the property for impairment. Cash flows used in the impairment analysis are determined based upon management’s estimates of probable and possible reserves, future commodity prices, and future costs to produce the reserves. Probable reserves are defined in SEC Regulation S-X, Rule 4-10(a)(18) as those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are more likely than not (generally having more than 50% probability) to be recovered. Possible reserves are defined in SEC Regulation S-X, Rule 4-10(a)(17) as those additional reserves that are less certain to be recovered than probable reserves. Estimates of cash flows related to probable and possible reserves are reduced by additional risk-weighting factors.
If undiscounted future net cash flows are less than the carrying value of the property, indicating impairment, the cash flows are discounted using a risk-adjusted rate and compared to the carrying value to determine the amount of the impairment loss to record.
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◦ | If proved reserves are discovered, the related acquisition costs are reclassified to proved properties. We assess proved crude oil and natural gas properties and other investments for possible impairment whenever events or circumstances indicate that the recorded carrying values of the assets may not be recoverable. We recognize an impairment loss as a result of an event that causes us to consider the possibility that impairment may have occurred and when the estimated undiscounted future net cash flows from a property or other investment are less than the carrying value. |
If impairment is indicated, the carrying values are written down to fair value, which, in the absence of comparable market data, is estimated using a discounted cash flow method. In our cash flow method, cash flows are discounted using a risk-adjusted rate and compared to the carrying value for determining the amount of the impairment loss to record. Estimated future net cash flows are based on management’s expectations for the future and include estimates of crude oil, natural gas and NGL reserves and future commodity prices, adjusted for location and quality differentials, revenues and operating and development costs.
Exploratory well costs - Costs associated with drilling an exploratory well may be capitalized temporarily, or “suspended,” pending a determination of whether crude oil or natural gas have been discovered and can be estimated with reasonable certainty to be economically producible. We carry the costs of an exploratory well as an asset if we have found a sufficient quantity of reserves to justify its completion as a producing well and as long as we are making sufficient progress assessing the reserves and the economic and operating viability of the project. For certain capital-intensive Gulf of Mexico or international projects, it may take several years to evaluate the future potential of the exploratory well and make a determination of its economic viability. Our ability to move forward on a project may be dependent on gaining access to transportation or processing facilities or obtaining permits and government or partner approval, the timing of which is beyond our control. In such cases, exploratory well costs remain suspended as long as
we are actively pursuing access to necessary facilities and submitting requests for permits and approvals and believe they will be obtained.
Development well costs - Costs associated with drilling a development well to obtain access to and to produce proved reserves are capitalized. Development well costs are included in our periodic proved property impairment test noted above.
These costs, along with those for support equipment and facilities, are amortized to expense by the unit-of-production method on a field-by-field basis, based on total proved crude oil, natural gas and NGL reserves, as estimated by our qualified petroleum engineers. Costs of certain gathering facilities or processing plants serving a number of properties or used for third-party processing are depreciated using the straight-line method over the useful lives of the assets.
The alternative method of accounting for crude oil and natural gas properties is the full cost method. Under the full cost method 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, under the full cost method, capitalized costs are accumulated in pools on a country-by-country basis. DD&A is computed on a country-by-country basis, and capitalized costs are limited on the same basis through the application of a ceiling test.
Judgment and Uncertainties The determination of the carrying value of our oil and gas properties includes assessment of impairment and the calculation of amortization expense.
In determination ofdetermining whether significant unproved crude oil and natural gas properties are impaired, we apply a significant amount of judgment in assessing entity-specific assumptions and assumptions related to the future economic environment, as well as potential impacts of the political and regulatory climate on future development activity. We also consider numerous factors including, but not limited to, current exploration plans, favorable or unfavorable exploration activity on the property being evaluated and/or adjacent properties, our geologists' evaluation of the property, and the remaining months in the lease term for the property.
In addition, impairment assessment involves a high degree of estimation uncertainty as it requires us to make assumptions and apply judgment to estimate future cash flows related to both proved and unproved reserves. Such assumptions include commodity prices, capital spending, production and abandonment costs and reservoir data. Significant judgment is involved in
estimating these factors, and they include uncertainties. In cases where probable and possible reserves cash flows are utilized to assess properties for impairment, we use the same pricing, cost and future production assumptions. For the purpose of impairment testing as of December 31, 2018, we used the five-year strip prices for crude oil and natural gas, with prices subsequent to the fifth year held constant as the benchmark price, unless contractual arrangements designate the price to be used, in the undiscounted future net cash flows. Capital and operating costs were estimated assuming 0% escalation.
We applyFor capitalized exploratory well costs, significant judgment is required in determiningorder 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 the exploratory wellsuch costs. Such assessment requires consideration of the following factors: commitment of project personnel, costs incurred to assess reserves and potential development, assessment process in progress coveringof 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 We have not made any material changes in the accounting methodology we use to account for our oil and gas properties. We believe the successful efforts method is the most appropriate method to use in accounting for our crude oil and natural gas properties because it provides a better representation of our results of operations, especially during periods of active exploration. If we had used the full cost method, our financial position and results of operations could have been significantly different.
At December 31, 2017,year-end, the net book value of our unproved properties includes significant amounts allocated in previous business combinations or acquisitions, including the Clayton Williams Energy Acquisition and the Rosetta Merger. See Supplemental Oil and Gas Information (Unaudited) - Capitalized Costs Relating to Oil and Gas Producing Activities.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. During 2017 we recognized undeveloped leasehold impairment expense of $62 million primarily attributable to Gulf of Mexico leases. We recorded leasehold impairment expense of $93 million in 2016 and $21 million in 2015. Impairment assessment incorporates expected future cash flows using expected prices, cost rates and future production. For the purpose of impairment testing, we used the five-year strip prices for crude oil and natural gas, with prices subsequent to the fifth year held constant as the benchmark price, unless contractual arrangements designate the price to be used, in the
undiscounted future net cash flows. Capital and operating costs were estimated assuming 0% escalation. Unfavorable changes in these pricing and cost assumptions in the future may result in negative revisions to ourproved and/or unproved reserves and associated cash flows, causing us to record impairment of proved and/or unproved oil and gas properties. We recorded total pre-tax (non-cash)An impairment charges of $70 milliona proved or unproved property could result in 2017, $92 milliona significant decrease in 2016, and $533 millionearnings.
At December 31, 2017, the balance of property, plant and equipment included $520 million of suspended exploratory well costs, $510 million of which had been capitalized for a period greater than one year. The wells relating to these suspended costs continue to be evaluated by various means, including additional seismic work, drilling additional appraisal wells to confirm the size of the hydrocarbon deposit, or evaluating the potential commerciality of the exploratory wells. During 2017, previously capitalized exploratory well costs of $65 million were expensed. See Item 8. Financial Statements and Supplementary Data - Note 6.7. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.Additionally, the carrying value of our oil and gas properties is sensitive to reserves estimates. Unit-of-production rates are revised at least once a year or when the reserves estimates are updated due to major revisions or transactions. The change in unit-of-production rates will affect the carrying value of our oil and gas properties and DD&A expense. If the estimates of proved reserves used in the unit-of-production calculations had been lower by 10% across all properties, 2017 DD&A expense would have increased by approximately $210 million.
Furthermore, a change in groupings of our oil and gas properties for the purpose of the DD&A calculation and impairment review could affect the calculation of unit-of-production rates, DD&A expense and determination of impairment.
Asset Retirement Obligations
DescriptionOur asset retirement obligations (AROs) consist of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. We recognize the fair value of an ARO liability in the period in which it is incurred, which is when we have an existing legal obligation associated with the retirement of our oil and gas properties and the obligation can be reasonably estimated.
The associated asset retirement cost is capitalized as part of the carrying cost of the oil and gas asset. In determining the fair value of an ARO, we utilize the estimated future cash flows method. The recognition of an ARO requires that management make numerous estimates, assumptions and judgments regarding such factors as: the existence of a legal obligation for an ARO; estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates.
In periods subsequent to initial measurement of the ARO, we recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted future cash flows. Revisions also result in increases or decreases in the carrying cost of the oil and gas asset. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through DD&A or exploration expense.
Judgment and Uncertainties The process for determining the fair value of an ARO requires us to make subjective judgments and assumptions concerning field life, timing of abandonment activities, cost structures, future labor rates and heavy equipment rental costs, expected inflation rates and changes in the regulatory environment. ARO estimates must be continually revised to reflect changes in these factors. Accordingly, we perform a comprehensive review of ARO estimates semi-annually with the proposed estimates and changes reflected in June 30 and December 31 period-end financial statements.
Effect if Actual Results Differ from Assumptions As of December 31, 2017, our consolidated balance sheet includes ARO liabilities of $875 million. Changes in the fair value of our ARO balance from prior year included both upward and downward revisions primarily due to revised timing and scope of remediation work resulting from assessment of abandonment work performed to-date and current cost experience on retirement obligations in the same operational areas. Future changes in rig rates, labor rates, inflation and interest rates, timing of settlements, scope of work, technological developments and changes in the environmental and regulatory climate may result in revisions to our ARO estimates which can be material to our financial position.
Purchase Price Allocations and Resulting Goodwill
DescriptionWe occasionally acquire assets and assume liabilities in transactions accounteduse the acquisition method to account for ascertain business combinations, such as the Clayton Williams Energy Acquisition in 2017 and the Rosetta Merger in 2015. In connection with a purchase business combination, the acquiring company mustcombinations. This method requires us to allocate the acquisition cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Deferred taxes must bedate, with any difference recorded for any differences between the assigned values and
tax bases of assets and liabilities. Any excess of the purchase price over amounts assigned to assets and liabilities is recordedeither as goodwill.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.
Goodwill Any goodwill recognized is not amortized to earnings but issubsequently assessed at least annually, for impairment atthrough an initial qualitative assessment, followed by the reporting unit level. A “reporting unit” is the level of reporting at which goodwill is tested for impairment. A reporting unit is an operating segment or one level below an operating segment. Our policy is to conduct a qualitative goodwill impairment assessment by examining relevant events and circumstances which could have a negative impact on our goodwill, such as: macroeconomic conditions; industry and market conditions, including commodity prices; cost factors; overall financial performance; reporting unit dispositions and acquisitions; and other relevant entity-specific events.
If, after assessing the totality of events or circumstances described above, we determine that it is more likely than not that the fair value of our Texas reporting unit is less than its carrying amount, the two-step goodwill test is performed. The two-step goodwill impairment test is also performed whenever events or changes in circumstances indicate that the carrying value may not be recoverable. If, after performing the two-step goodwill test, it is determined that the carrying value of goodwill is impaired, the amount of goodwill is reduced and a corresponding charge is made to earnings in the period in which the goodwill is determined to be impaired.
The two-step impairment test is used to identify potential goodwill impairment and measure the amount of a goodwill impairment loss to be recognized. The first stepapplication of the goodwill impairment test, used to identify potential impairment, compares the fair value of a reporting unit with its carrying amount, including goodwill. If the fair value of the reporting unit exceeds its carrying amount, goodwill is not considered to be impaired, and the second step of the test is not required. If necessary, the second step of the impairment test, used to measure the amount of impairment loss, compares the implied fair value of reporting unit goodwill with the carrying amount of that goodwill. If the carrying amount of reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess.quantitative test.
Judgment and Uncertainties Preparing a purchase price allocation requires estimating Estimation of the fair values of assets acquired and liabilities assumed in a business combination andrequires that we must make various assumptions. Theassumptions, the most significant assumptionsof 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 and NGL reserves utilizing the income approach.
The primary assumptions used to arrive at estimates of future net cash flows areused 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 riskingrisk 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.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.
Resulting goodwill from a purchase price allocation must be assessed for impairment. We perform our annual
The initial qualitative goodwill impairment test at the end of the third quarter of each year unlessassessment also involves significant judgment, as we are required to examine relevant events orand circumstances trigger the need for an interim impairment test.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.
The first step of the impairment test requires management toManagement must make estimates regarding the fair value of the reporting unit to which goodwill has been assigned. If it is necessaryWe use a combination of the income and market approaches to determine the fair value of the Texasa reporting unit, we use a combination of the income approach and the market approach.
Income Approach Under the income approach, theentity. These approaches result in fair value of the Texas reporting unit is estimated based on the present value of expected future cash flows. The income approach is dependent on a number of factors, including estimates of forecasted revenue and operating costs and proved reserves, as well as the success of future exploration for and development of unproved reserves, discount rates and other variables. Negative revisions of estimated reserves quantities, increases in future cost estimates, divestiture of a significant component of the reporting unit, or sustained decreases in crude oil or natural gas prices could lead to a reduction in expected future cash flows and possibly an impairment of all or a portion of goodwill in future periods. Key assumptions used in the discounted cash flow model described above include estimated quantities of crude oil, natural gas and NGL reserves, including both proved reserves and risk-adjusted unproved reserves; estimates of market prices considering forward commodity price curves as of the measurement date; and estimates of operating, administrative and capital costs adjusted for inflation. We discount the resulting future cash flows using a peer group based weighted average cost of capital.
Market Approach Under the market approach, we estimate the fair value of the Texas reporting unit by comparison to similar businesses whose securities are actively traded in the public market The market approach requires management to make certain judgments about the selection of comparable companies and/or comparable recent company and asset transactions and transaction premiums, thereby creating a group of guideline public companies or transactions, or a peer group,values that are engaged in similar operations with comparable risks and returns as our reporting unit.
We use the peer group multiple method for the market approach. Market multiples represent market estimates of fair value based on selected financial metrics. We use earnings before interest, taxes, DD&A and exploration expense (also known as EBITDAX) as our financial metric as we believe it more accurately compares companies using successful efforts and full cost accounting methods, both of which are in our peer group. Determination of fair value under the income approach and the market approach is subject to a high degree of estimation uncertainty as it requiresthey require us to make assumptions and apply judgment to various parameters that are sensitive to industry, market and economic conditions. The change in these factors inInputs for the future may have a negative impact on estimated future cash flowsincome approach include estimates of both proved reserves and risk-adjusted unproved reserves; market prices considering forward commodity price curves as of the enterprise valuemeasurement date; and operating, administrative and capital costs adjusted for inflation. Inputs for the market approach include selection of our reporting unit, which could result in future goodwill impairment.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 resulting 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 in the future. Aoperations. For example, a higher fair value assigned to a property results in higher DD&A expense, which results in lower net earnings. Fair values are based on estimates of future commodity prices, reserves quantities, operating expenses and development costs. This increases the likelihood of impairmentincome. 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 thosethe estimates originally used to determine fair value. Impairment would have no effect onvalue, the resulting reductions in future cash flows but would result incould indicate that a decrease in net income forproperty is impaired.
As of December 31, 2017, our consolidated balance sheet includes goodwill of $1.3 billion, resulting from the Clayton Williams Energy Acquisition in second quarter 2017. All of our recorded goodwill is assigned to the Texas reporting unit.
We conducted a qualitative and quantitative goodwill impairment assessment as of September 30, 2017 and based on the results of our goodwill impairment test, we concluded that our goodwill at September 30, 2017 was not impaired as the fair value of our Texas reporting unit was in excess of its respective net book value, including goodwill. While not required under Accounting Standards Codification (“ASC”) 350 “Intangibles - Goodwill and Other", we also performed a reconciliation of the determined enterprise fair value as compared to our total company market capitalization. From this additional analysis, we have concluded that the determination of the enterprise fair value closely aligns with our market capitalization.
The estimates used in our goodwill impairment test do not constitute forecasts or projections of future results of operations, but are rather estimates and assumptions based on historical results and assessments of macroeconomic factors affecting the Texas reporting unit as of the valuation date. We believe that our estimates and assumptions are reasonable, but they are subject to change from period to period. Actual results of operations and other factors will likely differ from the estimates used in our discounted cash flow valuation and it is possible that differences could be material. Although we base the fair value estimate of the Texas reporting unit on assumptions we believe to be reasonable, those assumptions are inherently unpredictable and uncertain and actual results could differ from the estimate. In the event of a prolonged industry downturn, commodity prices could again become depressed or decline, thereby causing the fair valuevalues of the Texasour reporting unitunits 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. The amount of goodwill to be included in that carrying amount will be based on the relative fair value of the business to be disposed of and the portion of the reporting unit that will be retained. See Item 8. Financial Statements and Supplementary Data - Note 3. Clayton Williams Energy Acquisition. Exit Costs
DescriptionWe account forOur consolidated balance sheets include accrued exit costs in accordance with ASC 420 - Exit or Disposal Cost Obligations, which requires that a liability for a cost associated with an exit or disposal activity be recognized at fair value in the period in which the liability is incurred. Further, a liability for costs that will continueliabilities relating to be incurred under a contract for its remaining term without economic benefit to the entity shall be recognized at the “cease-use date,” which is defined as the date the entity ceases using the right conveyed by the contract, for example, the right to use a leased property or to receive future goods or services.
During second quarter 2017, in connection with ourretained Marcellus Shale upstream divestiture, we accrued a liability of $41 million, discounted, for exit costs related to our commitment under a retainednatural gas firm transportation contract and charged the amount to loss on Marcellus Shale upstream divestiture in our consolidated statements of operations.contracts.
In addition, we have retained other Marcellus Shale firm transportation contracts, relating to pipeline projects that either were recently placed in service in late 2017/early 2018 or are not yet commercially available to us. These projects that are not yet available will undergo construction and, as these projects become commercially available to us, we will assess, based upon the facts and circumstances, the recognition of any potential exit cost liabilities. If we determine that we will not utilize a portion, or all, of the contracted pipeline capacity, we will accrue a liability, at fair value, for the amount of the estimated remaining financial commitment and include the related expense in operating expense in our consolidated statements of operations.
Any additional exit cost liability will be initially recorded at fair value, and, in periods subsequent to initial measurement, changes to the liability, including changes resulting from revisions to either the timing or the amount of estimated cash flows over the future contract period, will be recognized as an adjustment to the liability in the period of the change.
Judgment and Uncertainties We are required to make significant judgments and estimates regarding the timing and amount of recognition of any additional exit cost liabilities, taking into consideration ourcurrent 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 following:
the status of negotiations with counterparties regarding partialpermanent assignment or permanentcapacity release of our contract commitments;
the status of FERC approval of prospective pipeline projects;
the timing of commercial availability of approved pipelines upon completion of construction;commitments and
the likelihood of capacity utilization through purchase of third partythird-party natural gas, which would reduce unutilized volume commitments.
Additionally, any subsequent changes in interest rates and/or credit risk will affect the discount rate used to calculate the present value of expected future cash flows associated with our existing contract commitments.
There are inherent uncertainties surrounding the recording of exit cost liabilities, and, in future periods, a number of factors could significantly change our estimate of such obligations or result in recognition of additional liabilityliability.
Effect if Actual Results Differ from Assumptions As 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, 2017 our2018, we have a significant remaining financial commitment associated with Marcellus Shale firm transportation contracts was approximately $1.4 billion, undiscounted. We are currently engaged in actions to commercialize and address these remaining commitments, which would reduce our undiscounted financial commitment.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
DescriptionWe are subjectOur consolidated balance sheets include deferred tax assets and liabilities relating to incometemporary differences, operating losses, and other taxes in numerous taxing jurisdictions worldwide. For financial reporting purposes, we provide taxes at rates applicable fortax-credit carryforwards. Valuation allowances may reduce the appropriatedeferred tax jurisdictions. 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 including the recently enacted Tax Cuts and Jobs Act, as well as assessment of the effects of foreign taxes on domestic taxes, and estimates regarding the timing and amounts of future repatriation of earnings from controlled foreign corporations.
Our consolidated balance sheets include deferred tax assets. Deferred tax assets arise when expenses are recognized in the financial statements before they are recognized in the tax returns or when income items are recognized in the tax returns before they are recognized in the financial statements. Deferred tax assets also arise when operating losses or tax credits are available to offset tax payments due in future years. Ultimately, realization of a deferred tax asset depends on the existence of sufficient taxable income within the future periods to absorb future deductible temporary differences, loss carryforwards or credits.
In assessing the realizability of deferred tax assets, management must consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized.
Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgment is required in considering the relative weight of negative and positive evidence. We continue to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets will be utilized prior to their expiration. As a result, we may determine, and we have determined in the past, that a deferred tax asset valuation allowance should be established.
Judgment and Uncertainties In assessing facts and circumstances surrounding realizability of our deferred tax assets we are required to apply judgment to determine the weight of both positive and negative evidence in order to conclude whether the valuation allowance is necessary relative to net operating loss carryforwards and other deferred tax assets.
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 AsWe continue to monitor facts and circumstances in the reassessment of December 31, 2017, our US federal income tax netthe likelihood that operating loss carryforwards, totaled approximately $3.2 billioncredits and foreign net operating loss carryforwards were $662 million. The deferred tax asset associated with our federal and foreign net operating loss carryforwards was approximately $672 million and $187 million, respectively, classified, net, in our consolidated balance sheet within noncurrent deferred income tax liability balance. We currently have a valuation allowance on theother deferred tax assets associated with foreign loss carryforwards and foreign tax credits. The valuation allowance on foreign loss carryforwards totaled $183 million in 2017 and $242 million in 2016. The changeswill be utilized prior to the valuation allowance for the loss carryforwards between periods was attributabletheir expiration. Changes to the offsetour current financial position, results of the valuation allowance against the NOL in a jurisdiction in which we are no longer active. Deemed foreign tax credits of $164 million were recognized along with the additionaloperations, projected future taxable income, associated with the transition tax. A full valuation allowance of $366 million has been recorded against all foreign tax credits based on current interpretation of US Tax Reform law and the expected future utilization of net operating loss carryforwards. Any increase planning strategies and/or decrease innew tax legislation may be deemed significant enough to necessitate a change to our deferred tax asset valuation allowance wouldallowances in the future, in which case the increases or decreases could significantly impact net income through offsetting changes in income tax expense, which could have a negative impact on our financial position and results of operations.expense. See Item 8. Financial Statements and Supplementary Data -– Note 11.12. Income Taxes. Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Derivative Instruments Held for Non-Trading PurposesWe areexposed to commodity pricemarket risk in the normal course of business operations. operations, and the volatility of crude oil and natural gas prices continues to impact the oil and gas industry.
Derivative Instruments Held for Non-Trading PurposesDue to commodity price volatility, we may use derivative instruments as a means of managing our exposure to price changes.
At December 31, 2017,2018, we had various open commodity derivative instruments related to global crude oil and domestic natural gas. Changes in fair value of commodity derivative instruments are reported in earnings in the period in which they occur. Our open commodity derivative instruments were in a net liabilityasset position at December 31, 2017 with a fair value of $71$153 million. Based on the December 31, 20172018 published commodity futures price curves for the underlying commodities, a hypothetical price increase of 10% per Bbl for crude oil and 10% per MMBtu for natural gas would increasedecrease the fair value of our net commodity derivative liabilityasset by approximately $146$272 million. A hypothetical price increase of 10% per MMBtu for natural gas would increase the fair value of our net commodity derivative liability by approximately $5 million.
Our derivative instruments are executed under master agreements which allow us to net settle by counterparty. Net settlements take into account deferred premiums we have agreed to pay for put options. In addition, in the event of default, these master agreements allow us to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net cash settled at the time of election. None of our counterparty agreements contain margin requirements.
Even with certain hedging arrangements in place to mitigate the effect of commodity price volatility, our 20182019 revenues and results of operations could be adversely affected if commodity prices were to decline. See Item 1A. Risk Factors – Commodity hedging transactions may limit our potential gains or fail to protect us from declines in commodity pricesand Item 8. Financial Statements and Supplementary Data – Note 8.13. Derivative Instruments and Hedging Activities. Interest Rate Risk
Changes in interest rates affect the amount of interest we pay on borrowings undercertain of our credit facilitiesborrowings and the amount of interest we earn on our short-term investments.
At December 31, 2017,2018, we had approximately $6.5$6.4 billion (excluding capital lease and other obligations) of long-term debt outstanding.outstanding, net of unamortized discount and debt issuance costs. Of this amount, approximately $6.3$5.8 billion was fixed-rate debt, net of unamortized discount and debt issuance costs, with a weighted average interest rate of 5.04%5.06% at December 31, 2017.2018. Although near term changes in interest rates may affect the fair value of our fixed-rate debt, they do not expose us to theinterest rate risk of earnings or cash flow loss. See Item 8. Financial Statements and Supplementary Data – Note 10. Long-Term Debt. WeHowever, we are also exposed to interest rate risk related to our interest-bearing cash and cash equivalents balances and amounts outstanding under our credit facilities.balances. As of December 31, 2017,2018, our cash and cash equivalents totaled approximately $675$716 million, approximately 59% 25% of which was invested in money market funds and short-term investments with major financial institutions.
In addition, issuances of commercial paper 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 Facility are subject to variable interest rates which expose us to the risk of earnings or cash flow loss due to potential increases in market interest rates. A change in the interest rate applicable to our short termvariable-rate debt could expose us to additional interest cost. While we currently have no interest rate derivative instruments as of December 31, 2018, we may invest in such instruments in the future in order to mitigate interest rate risk. A change in the interest rate applicable to our short-term investments or amounts, if any, outstanding under our creditthe above-named facilities would have a de minimis impact on our earningsconsolidated net income. See Item 8. Financial Statements and cash flows. We currently have no interest rate derivative
instruments outstanding. However, we may enter into interest rate derivative instruments in the future if we determine that it is necessary to invest in such instruments in order to mitigate our interest rate risk.9. Long-Term Debt.
Foreign Currency Risk
The US dollar is considered the functional currency for each of our international operations. Substantially all of our international crude oil, NGL and natural gas and NGL production is sold pursuant to US dollar denominated contracts. Transactions, such as operating costs and administrative expenses that are paid in a foreign currency, are remeasured into US dollars and recorded in the financial statements at prevailing currency exchange rates. Certain monetary assets and liabilities, for example certain local working capital items, areare denominated in a foreign currency and remeasured into US dollars. A reduction in the value of the US dollar against currencies of other countries in which we have material operations could result in the use of additional cash to settle operating, administrative and tax liabilities. This risk may be mitigated to the extent commodity prices increase in response to a devaluation of the US dollar.
Net foreign transaction (gains)gains and losses were de minimis for 2018, 2017 2016 and 2015. Foreign transaction (gains) losses are included in other (income) expense, net in the consolidated statements of operations.2016.
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.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, 2017,2018, our management assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established in Internal Control – Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, management determined that we maintained effective internal control over financial reporting as of December 31, 2017,2018, 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, 20172018 which is included herein.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and StockholdersShareholders
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”)Company) as of December 31, 20172018 and 2016,2017, the related consolidated statements of operations and comprehensive income (loss), shareholders’ equity, and cash flows for each of the years in the three-yearthree‑year period ended December 31, 2017,2018, and the related notes (collectively, the “consolidatedconsolidated financial statements”)statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20172018 and 2016,2017, and the results of its operations and its cash flows for each of the years in the three-yearthree‑year period ended December 31, 2017,2018, 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”)(PCAOB), the Company’s internal control over financial reporting as of December 31, 2017,2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 20, 201819, 2019 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
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| | | /s/ KPMG LLP | | |
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| We have served as the Company’s auditor since 2002. |
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| Houston, Texas | | | | |
February 20, 201819, 2019 | | | | |
Report of Independent Registered Public Accounting Firm
To the Board of Directors and StockholdersShareholders
Noble Energy, Inc.:
Opinion on Internal Control Over Financial Reporting
We have audited Noble Energy, Inc.’s's andsubsidiaries’ (the “Company”)Company) internal control over financial reporting as of December 31, 2017,2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2018, 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”)(PCAOB), the consolidated balance sheets of the Company as of December 31, 20172018 and 2016,2017, the related consolidated statements of operations and comprehensive income (loss), shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2017,2018, and the related notes (collectively, the “consolidatedconsolidated financial statements”)statements), and our report dated February 20, 201819, 2019 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 reportManagement’s Report on internal controlsInternal Controls over financial reporting.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 20, 201819, 2019 | | | | |
Noble Energy, Inc.
Consolidated Statements of Operations and Comprehensive Income (Loss)
(millions, except per share amounts)
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| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Revenues | | | | | |
| Oil, NGL and Gas Sales | $ | 4,461 |
| | $ | 4,060 |
| | $ | 3,389 |
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| Sales of Purchased Oil and Gas and Other | 525 |
| | 196 |
| | 102 |
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| Total | 4,986 |
| | 4,256 |
| | 3,491 |
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| Costs and Expenses | | | | | |
| Production Expense | 1,197 |
| | 1,141 |
| | 1,100 |
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| Exploration Expense | 129 |
| | 188 |
| | 925 |
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| Depreciation, Depletion and Amortization | 1,934 |
| | 2,053 |
| | 2,454 |
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| Loss on Marcellus Shale Upstream Divestiture and Other | — |
| | 2,379 |
| | — |
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| Gain on Divestitures, Net | (843 | ) | | (326 | ) | | (238 | ) |
| Asset Impairments | 206 |
| | 70 |
| | 92 |
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| Goodwill Impairment | 1,281 |
| | — |
| | — |
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| General and Administrative | 385 |
| | 415 |
| | 399 |
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| Other Operating Expense, Net | 346 |
| | 138 |
| | 135 |
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| Total | 4,635 |
| | 6,058 |
| | 4,867 |
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| Operating Income (Loss) | 351 |
| | (1,802 | ) | | (1,376 | ) |
| Other Expense | | | | | |
| (Gain) Loss on Commodity Derivative Instruments | (63 | ) | | (63 | ) | | 139 |
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| Loss (Gain) on Extinguishment of Facility or Debt | 8 |
| | 98 |
| | (80 | ) |
| Interest, Net of Amount Capitalized | 282 |
| | 354 |
| | 328 |
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| Other Non-Operating (Income) Expense, Net | (16 | ) | | — |
| | 9 |
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| Total | 211 |
| | 389 |
| | 396 |
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| 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 | ) |
| Less: Net Income and Comprehensive Income Attributable to Noncontrolling Interests | 80 |
| | 68 |
| | 13 |
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| Net Loss and Comprehensive Loss Attributable to Noble Energy | $ | (66 | ) | | $ | (1,118 | ) | | $ | (998 | ) |
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| Loss Attributable to Noble Energy per Common Share | | | | | |
| Basic and Diluted | $ | (0.14 | ) | | $ | (2.38 | ) | | $ | (2.32 | ) |
| Weighted Average Number of Shares Outstanding | | | | | |
| Basic and Diluted | 483 |
| | 469 |
| | 430 |
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| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Revenues | | | | | |
| Oil, Gas and NGL Sales | $ | 4,060 |
| | $ | 3,389 |
| | $ | 3,093 |
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| Income from Equity Method Investees and Other | 196 |
| | 102 |
| | 90 |
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| Total Revenues | 4,256 |
| | 3,491 |
| | 3,183 |
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| Costs and Expenses | | | | | |
| Production Expense | 1,141 |
| | 1,100 |
| | 996 |
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| Exploration Expense | 188 |
| | 925 |
| | 488 |
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| Depreciation, Depletion and Amortization | 2,053 |
| | 2,454 |
| | 2,131 |
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| General and Administrative | 415 |
| | 399 |
| | 396 |
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| Loss on Marcellus Shale Upstream Divestiture | 2,379 |
| | — |
| | — |
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| Asset Impairments | 70 |
| | 92 |
| | 533 |
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| Goodwill Impairment | — |
| | — |
| | 779 |
|
| Other Operating (Income) Expense, Net | (188 | ) | | (103 | ) | | 332 |
|
| Total Operating Expenses | 6,058 |
| | 4,867 |
| | 5,655 |
|
| Operating Loss | (1,802 | ) | | (1,376 | ) | | (2,472 | ) |
| Other Expense (Income) | | | | | |
| (Gain) Loss on Commodity Derivative Instruments | (63 | ) | | 139 |
| | (501 | ) |
| Loss (Gain) on Extinguishment of Debt | 98 |
| | (80 | ) | | — |
|
| Interest, Net of Amount Capitalized | 354 |
| | 328 |
| | 263 |
|
| Other Non-Operating Expense (Income), Net | — |
| | 9 |
| | (15 | ) |
| Total Other Expense (Income) | 389 |
| | 396 |
| | (253 | ) |
| Loss Before Income Taxes | (2,191 | ) | | (1,772 | ) | | (2,219 | ) |
| Income Tax (Benefit) Provision | (1,141 | ) | | (787 | ) | | 222 |
|
| Net Loss Including Noncontrolling Interests | (1,050 | ) | | (985 | ) | | (2,441 | ) |
| Less: Net Income Attributable to Noncontrolling Interests | 68 |
| | 13 |
| | — |
|
| Net Loss Attributable to Noble Energy | $ | (1,118 | ) | | $ | (998 | ) | | $ | (2,441 | ) |
| | | | | | |
| Net Loss Attributable to Noble Energy per Share of Common Stock | | | | | |
| Basic and Diluted | $ | (2.38 | ) | | $ | (2.32 | ) | | $ | (6.07 | ) |
| | | | | | |
| Weighted Average Number of Shares Outstanding | | | | | |
| Basic and Diluted | 469 |
| | 430 |
| | 402 |
|
The accompanying notes are an integral part of these financial statements.
Noble Energy, Inc.
Consolidated Statements of Comprehensive Income (Loss)Balance Sheets
(millions)
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Net Loss Including Noncontrolling Interests | $ | (1,050 | ) | | $ | (985 | ) | | $ | (2,441 | ) |
| Other Items of Comprehensive Loss | | | | | |
| Net Change in Mutual Fund Investment | — |
| | — |
| | (11 | ) |
| Less Tax Expense | — |
| | — |
| | 4 |
|
| Net Change in Pension and Other | 3 |
| | 3 |
| | 99 |
|
| Less Tax Benefit | (1 | ) | | (1 | ) | | (35 | ) |
| Other Comprehensive Income | 2 |
| | 2 |
| | 57 |
|
| Comprehensive Loss Including Noncontrolling Interests | $ | (1,048 | ) | | $ | (983 | ) | | $ | (2,384 | ) |
| Less: Comprehensive Income Attributable to Noncontrolling Interests | 68 |
| | 13 |
| | — |
|
| Comprehensive Loss Attributable to Noble Energy | $ | (1,116 | ) | | $ | (996 | ) | | $ | (2,384 | ) |
|
| | | | | | | |
| | December 31,
2018 | | December 31,
2017 |
| ASSETS | | | |
| Current Assets | | | |
| Cash and Cash Equivalents | $ | 716 |
| | $ | 675 |
|
| Accounts Receivable, Net | 616 |
| | 748 |
|
| Other Current Assets | 418 |
| | 780 |
|
| Total Current Assets | 1,750 |
| | 2,203 |
|
| Property, Plant and Equipment | | | |
| Oil and Gas Properties (Successful Efforts Method of Accounting) | 29,002 |
| | 29,678 |
|
| Property, Plant and Equipment, Other | 891 |
| | 879 |
|
| Total Property, Plant and Equipment, Gross | 29,893 |
| | 30,557 |
|
| Accumulated Depreciation, Depletion and Amortization | (11,474 | ) | | (13,055 | ) |
| Total Property, Plant and Equipment, Net | 18,419 |
| | 17,502 |
|
| Other Noncurrent Assets | 731 |
| | 461 |
|
| Goodwill | 110 |
| | 1,310 |
|
| Total Assets | $ | 21,010 |
| | $ | 21,476 |
|
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | |
| Current Liabilities | | | |
| Accounts Payable - Trade | $ | 1,207 |
| | $ | 1,161 |
|
| Other Current Liabilities | 519 |
| | 578 |
|
| Total Current Liabilities | 1,726 |
| | 1,739 |
|
| Long-Term Debt | 6,574 |
| | 6,746 |
|
| Deferred Income Taxes | 1,061 |
| | 1,127 |
|
| Other Noncurrent Liabilities | 1,165 |
| | 1,245 |
|
| Total Liabilities | 10,526 |
| | 10,857 |
|
| Commitments and Contingencies | | | |
| Shareholders’ Equity | | | |
| Preferred Stock - Par Value $1.00 per share; 4 Million Shares Authorized; None Issued | — |
| | — |
|
| Common Stock - Par Value $0.01 per share; 1 Billion Shares Authorized; 520 Million and 529 Million Shares Issued, respectively | 5 |
| | 5 |
|
| Additional Paid in Capital | 8,203 |
| | 8,438 |
|
| Accumulated Other Comprehensive Loss | (32 | ) | | (30 | ) |
| Treasury Stock, at Cost; 39 Million Shares | (730 | ) | | (725 | ) |
| Retained Earnings | 1,980 |
| | 2,248 |
|
| Noble Energy Share of Equity | 9,426 |
| | 9,936 |
|
| Noncontrolling Interests | 1,058 |
| | 683 |
|
| Total Equity | 10,484 |
| | 10,619 |
|
| Total Liabilities and Equity | $ | 21,010 |
| | $ | 21,476 |
|
The accompanying notes are an integral part of these financial statements.
Noble Energy, Inc.
Consolidated Balance Sheets
(millions)
|
| | | | | | | |
| | December 31,
2017 | | December 31,
2016 |
| ASSETS | | | |
| Current Assets | | | |
| Cash and Cash Equivalents | $ | 675 |
| | $ | 1,180 |
|
| Accounts Receivable, Net | 748 |
| | 615 |
|
| Other Current Assets | 780 |
| | 160 |
|
| Total Current Assets | 2,203 |
| | 1,955 |
|
| Property, Plant and Equipment | | | |
| Oil and Gas Properties (Successful Efforts Method of Accounting) | 29,678 |
| | 30,355 |
|
| Property, Plant and Equipment, Other | 879 |
| | 909 |
|
| Total Property, Plant and Equipment, Gross | 30,557 |
| | 31,264 |
|
| Accumulated Depreciation, Depletion and Amortization | (13,055 | ) | | (12,716 | ) |
| Total Property, Plant and Equipment, Net | 17,502 |
| | 18,548 |
|
| Goodwill | 1,310 |
| | — |
|
| Other Noncurrent Assets | 461 |
| | 508 |
|
| Total Assets | $ | 21,476 |
| | $ | 21,011 |
|
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | |
| Current Liabilities | | | |
| Accounts Payable - Trade | $ | 1,161 |
| | $ | 736 |
|
| Other Current Liabilities | 578 |
| | 742 |
|
| Total Current Liabilities | 1,739 |
| | 1,478 |
|
| Long-Term Debt | 6,746 |
| | 7,011 |
|
| Net Deferred Income Tax Liability | 1,127 |
| | 1,819 |
|
| Other Noncurrent Liabilities | 1,245 |
| | 1,103 |
|
| Total Liabilities | 10,857 |
| | 11,411 |
|
| | | | |
| Shareholders’ Equity | | | |
| Preferred Stock - Par Value $1.00 per share; 4 Million Shares Authorized, None Issued | — |
| | — |
|
| Common Stock - Par Value $0.01; 1 Billion Shares Authorized; 529 Million and 471 Million Shares Issued, Respectively | 5 |
| | 5 |
|
| Additional Paid in Capital | 8,438 |
| | 6,450 |
|
| Accumulated Other Comprehensive Loss | (30 | ) | | (31 | ) |
| Treasury Stock, at Cost; 39 Million and 38 Million Shares, Respectively | (725 | ) | | (692 | ) |
| Retained Earnings | 2,248 |
| | 3,556 |
|
| Noble Energy Share of Equity | 9,936 |
| | 9,288 |
|
| Noncontrolling Interests | 683 |
| | 312 |
|
| Total Equity | 10,619 |
| | 9,600 |
|
| Total Liabilities and Equity | $ | 21,476 |
| | $ | 21,011 |
|
The accompanying notes are an integral part of these financial statements.
Noble Energy, Inc.
Consolidated Statements of Cash Flows
(millions)
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| 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 | |
| | |
| | |
| Depreciation, Depletion and Amortization | 1,934 |
| | 2,053 |
| | 2,454 |
|
| Loss on Marcellus Shale Upstream Divestiture and Other | — |
| | 2,379 |
| | — |
|
| Gain on Divestitures, Net | (843 | ) | | (326 | ) | | (238 | ) |
| Asset Impairments | 206 |
| | 70 |
| | 92 |
|
| Goodwill Impairment | 1,281 |
| | — |
| | — |
|
| Deferred Income Tax Benefit | (70 | ) | | (1,227 | ) | | (984 | ) |
| 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 |
|
| Stock Based Compensation | 62 |
| | 104 |
| | 77 |
|
| 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 |
|
| 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 | ) |
| Other Current Assets and Liabilities, Net | (36 | ) | | (71 | ) | | (76 | ) |
| Other Operating Assets and Liabilities, Net | (126 | ) | | (120 | ) | | (90 | ) |
| Net Cash Provided by Operating Activities | 2,336 |
| | 1,951 |
| | 1,351 |
|
| Cash Flows From Investing Activities | |
| | |
| | |
| Additions to Property, Plant and Equipment | (3,279 | ) | | (2,649 | ) | | (1,541 | ) |
| Acquisitions, Net of Cash Received | (653 | ) | | (954 | ) | | 30 |
|
| Proceeds from Divestitures | 1,999 |
| | 2,073 |
| | 1,241 |
|
| Marcellus Shale Acreage Exchange Consideration | — |
| | — |
| | (213 | ) |
| Other | 2 |
| | (87 | ) | | 82 |
|
| Net Cash Used in Investing Activities | (1,931 | ) | | (1,617 | ) | | (401 | ) |
| Cash Flows From Financing Activities | |
| | |
| | |
| Proceeds from Revolving Credit Facility | 1,580 |
| | 1,585 |
| | — |
|
| Repayment of Revolving Credit Facility | (1,810 | ) | | (1,355 | ) | | — |
|
| Proceeds from Term Loan Facility | — |
| | — |
| | 1,400 |
|
| Repayment of Term Loan Facility | — |
| | (550 | ) | | (850 | ) |
| Proceeds from Noble Midstream Services Revolving Credit Facility | 777 |
| | 325 |
| | — |
|
| Repayment of Noble Midstream Services Revolving Credit Facility | (802 | ) | | (240 | ) | | — |
|
| Proceeds from Noble Midstream Services Term Loan Credit Facility | 500 |
| | — |
| | — |
|
| Repayment of Senior Notes | (384 | ) | | (1,114 | ) | | (1,383 | ) |
| Repayment of Clayton Williams Energy Long-term Debt | — |
| | (595 | ) | | — |
|
| Proceeds from Issuance of Senior Notes | — |
| | 1,086 |
| | — |
|
| Dividends Paid, Common Stock | (208 | ) | | (190 | ) | | (172 | ) |
| Purchase and Retirement of Common Stock | (295 | ) | | — |
| | — |
|
| Issuance of Noble Midstream Partners Common Units, Net of Offering Costs | — |
| | 312 |
| | 299 |
|
| Contributions from Noncontrolling Interest Owners | 353 |
| | 19 |
| | — |
|
| Other | (110 | ) | | (114 | ) | | (62 | ) |
| Net Cash Used in Financing Activities | (399 | ) | | (831 | ) | | (768 | ) |
| Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash | 6 |
| | (497 | ) | | 182 |
|
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 713 |
| | 1,210 |
| | 1,028 |
|
| Cash, Cash Equivalents, and Restricted Cash at End of Period | $ | 719 |
| | $ | 713 |
| | $ | 1,210 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Cash Flows From Operating Activities | | | | | |
| Net Loss Including Noncontrolling Interests | $ | (1,050 | ) | | $ | (985 | ) | | $ | (2,441 | ) |
| Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities | |
| | |
| | |
| Depreciation, Depletion and Amortization | 2,053 |
| | 2,454 |
| | 2,131 |
|
| Asset Impairments | 70 |
| | 92 |
| | 533 |
|
| Loss on Marcellus Shale Upstream Divestiture | 2,379 |
| | — |
| | — |
|
| Goodwill Impairment | — |
| | — |
| | 779 |
|
| Dry Hole Cost | 9 |
| | 579 |
| | 266 |
|
| Deferred Income Taxes | (1,227 | ) | | (984 | ) | | 116 |
|
| (Gain) Loss on Commodity Derivative Instruments | (63 | ) | | 139 |
| | (501 | ) |
| Net Cash Received in Settlement of Commodity Derivative Instruments | 13 |
| | 569 |
| | 1,009 |
|
| Gain on Divestitures | (326 | ) | | (238 | ) | | — |
|
| Stock Based Compensation | 104 |
| | 77 |
| | 86 |
|
| Non-cash Pension Plan Termination Expense | — |
| | — |
| | 82 |
|
| Loss (Gain) on Debt Extinguishment | 98 |
| | (80 | ) | | — |
|
| Undeveloped Leasehold Impairment | 62 |
| | 93 |
| | 21 |
|
| Expiration and Amortization of Undeveloped Leaseholds | — |
| | 55 |
| | 92 |
|
| Other Adjustments for Noncash Items Included in Income | (21 | ) | | 40 |
| | 18 |
|
| Changes in Operating Assets and Liabilities, Net of Assets Acquired and Liabilities Assumed | | | | | |
| (Increase) Decrease in Accounts Receivable | (171 | ) | | (164 | ) | | 453 |
|
| Increase (Decrease) in Accounts Payable | 248 |
| | (111 | ) | | (364 | ) |
| (Decrease) Increase in Current Income Taxes Payable | (36 | ) | | (32 | ) | | (94 | ) |
| (Decrease) Increase in Other Current Liabilities | (101 | ) | | (63 | ) | | (70 | ) |
| Other Operating Assets and Liabilities, Net | (90 | ) | | (90 | ) | | (54 | ) |
| Net Cash Provided by Operating Activities | 1,951 |
| | 1,351 |
| | 2,062 |
|
| Cash Flows From Investing Activities | |
| | |
| | |
| Additions to Property, Plant and Equipment | (2,649 | ) | | (1,541 | ) | | (2,979 | ) |
| Proceeds from Divestitures | 2,073 |
| | 1,241 |
| | 151 |
|
| Clayton Williams Energy Acquisition, Net of Cash Received | (616 | ) | | — |
| | — |
|
| Other Acquisitions | (327 | ) | | — |
| | — |
|
| Marcellus Shale Acreage Exchange Consideration | — |
| | (213 | ) | | — |
|
| Other | (87 | ) | | 82 |
| | (43 | ) |
| Net Cash Used in Investing Activities | (1,606 | ) | | (431 | ) | | (2,871 | ) |
| Cash Flows From Financing Activities | |
| | |
| | |
| Dividends Paid, Common Stock | (190 | ) | | (172 | ) | | (291 | ) |
| Proceeds from Issuance of Noble Energy Common Stock, Net of Offering Costs | — |
| | — |
| | 1,112 |
|
| Proceeds from Revolving Credit Facility | 1,585 |
| | — |
| | — |
|
| Repayment of Revolving Credit Facility | (1,355 | ) | | — |
| | (70 | ) |
| Repayment of Clayton Williams Energy Long-term Debt | (595 | ) | | — |
| | — |
|
| Proceeds from Term Loan Facility | — |
| | 1,400 |
| | — |
|
| Repayment of Term Loan Facility | (550 | ) | | (850 | ) | | — |
|
| Proceeds from Issuance of Senior Notes, Net | 1,086 |
| | — |
| | — |
|
| Repayment of Senior Notes | (1,114 | ) | | (1,383 | ) | | (12 | ) |
| Proceeds from Noble Midstream Services Revolving Credit Facility | 325 |
| | — |
| | — |
|
| Repayment of Noble Midstream Services Revolving Credit Facility | (240 | ) | | — |
| | — |
|
| Proceeds from Issuance of Noble Midstream Partners Common Units, Net of Offering Costs | 312 |
| | 299 |
| | — |
|
| Other | (114 | ) | | (62 | ) | | (85 | ) |
| Net Cash (Used in) Provided By Financing Activities | (850 | ) | | (768 | ) | | 654 |
|
| (Decrease) Increase in Cash and Cash Equivalents | (505 | ) | | 152 |
| | (155 | ) |
| Cash and Cash Equivalents at Beginning of Period | 1,180 |
| | 1,028 |
| | 1,183 |
|
| Cash and Cash Equivalents at End of Period | $ | 675 |
| | $ | 1,180 |
| | $ | 1,028 |
|
The accompanying notes are an integral part of these financial statements.
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, 2014 | $ | 4 |
| | $ | 3,624 |
| | $ | (90 | ) | | $ | (671 | ) | | $ | 7,458 |
| | — |
| | $ | 10,325 |
| |
| Net Loss | — |
| | — |
| | — |
| | — |
| | (2,441 | ) | | — |
| | (2,441 | ) | |
| Rosetta Merger | 1 |
| | 1,528 |
| | — |
| | — |
| | — |
| | — |
| | 1,529 |
| |
| Stock-based Compensation | — |
| | 86 |
| | — |
| | — |
| | — |
| | — |
| | 86 |
| |
| Exercise of Stock Options | — |
| | 8 |
| | — |
| | — |
| | — |
| | — |
| | 8 |
| |
| Dividends (72 cents per share) | — |
| | — |
| | — |
| | — |
| | (291 | ) | | — |
| | (291 | ) | |
| Issuance of Shares of Noble Energy Common Stock to Public, Net of Offering Costs | — |
| | 1,112 |
| | — |
| | — |
| | — |
| | — |
| | 1,112 |
| |
| Net Change in Other | — |
| | 2 |
| | 57 |
| | (17 | ) | | — |
| | — |
| | 42 |
| |
| December 31, 2015 | $ | 5 |
| | $ | 6,360 |
| | $ | (33 | ) | | $ | (688 | ) | | $ | 4,726 |
| | — |
| | $ | 10,370 |
| $ | 5 |
| | $ | 6,360 |
| | $ | (33 | ) | | $ | (688 | ) | | $ | 4,726 |
| | $ | — |
| | $ | 10,370 |
|
| Net (Loss) Income | — |
| | — |
| | — |
| | — |
| | (998 | ) | | 13 |
| | (985 | ) | — |
| | — |
| | — |
| | — |
| | (998 | ) | | 13 |
| | (985 | ) |
| Stock-based Compensation | — |
| | 68 |
| | — |
| | — |
| | — |
| | — |
| | 68 |
| — |
| | 68 |
| | — |
| | — |
| | — |
| | — |
| | 68 |
|
| Exercise of Stock Options | — |
| | 24 |
| | — |
| | — |
| | — |
| | — |
| | 24 |
| — |
| | 24 |
| | — |
| | — |
| | — |
| | — |
| | 24 |
|
| Dividends (40 cents per share) | — |
| | — |
| | — |
| | — |
| | (172 | ) | | — |
| | (172 | ) | — |
| | — |
| | — |
| | — |
| | (172 | ) | | — |
| | (172 | ) |
| Issuance of Noble Midstream Partners Common Units, Net of Offering Costs | — |
| | — |
| | — |
| | — |
| | — |
| | 299 |
| | 299 |
| — |
| | — |
|
| — |
| | — |
| | — |
| | 299 |
|
| 299 |
|
| Net Change in Other | — |
| | (2 | ) | | 2 |
| | (4 | ) | | — |
| | — |
| | (4 | ) | |
| 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 | ) |
| Net Change in Other | — |
| | 2 |
| | 1 |
| | (8 | ) | | — |
| | 19 |
| | 14 |
| |
| Other | | — |
| | 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 |
|
| Stock-based Compensation | | — |
| | 78 |
| | — |
| | — |
| | — |
| | — |
| | 78 |
|
| Dividends (43 cents per share) | | — |
| | — |
| | — |
| | — |
| | (208 | ) | | — |
| | (208 | ) |
| Purchase and Retirement of Common Stock | | — |
| | (295 | ) | | — |
| | — |
| | — |
| | — |
| | (295 | ) |
| Clayton Williams Energy Acquisition | | — |
| | (25 | ) | | — |
| | — |
| | — |
| | — |
| | (25 | ) |
| Distributions to Noncontrolling Interest Owners | | — |
| | — |
| | — |
| | — |
| | — |
| | (51 | ) | | (51 | ) |
| Contributions from Noncontrolling Interest Owners | | — |
| | — |
| | — |
| | — |
| | — |
| | 353 |
| | 353 |
|
| Other | | — |
| | 7 |
| | (2 | ) | | (5 | ) | | 6 |
| | (7 | ) | | (1 | ) |
| December 31, 2018 | | $ | 5 |
| | $ | 8,203 |
| | $ | (32 | ) | | $ | (730 | ) | | $ | 1,980 |
| | $ | 1,058 |
| | $ | 10,484 |
|
The accompanying notes are an integral part of these financial statements.
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Note 1. Summary of Significant Accounting Policies
General Noble Energy, Inc. (Noble Energy, we or us) is a leading independent energy company engaged in worldwide crude oil and natural gas exploration and production. Our historical operating areas include: US onshore, primarily the DJ Basin, Delaware Basin, Eagle Ford Shale and Marcellus Shale (until June 2017); US offshore Gulf of Mexico;Mexico (until April 2018); Eastern Mediterranean; and West Africa. Our Midstream segment develops, owns, operates develops and acquires domestic midstream infrastructure assets, or invests in other midstream entities, with current focus areas being the DJ and Delaware Basins.
Basis of Presentation and Consolidation AccountingWe use accounting policies used by us and our subsidiariesthat conform to US GAAP. Significant policies are discussed below. Our consolidated accounts include our accounts and the accounts of our wholly-owned subsidiaries. All significant intercompany balances and transactions have been eliminated upon consolidation. For the periods presented, net income or loss is materially consistent with comprehensive income or loss.
Segment InformationAccounting 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 Energy has determined that the partners with equity at risk in Noble Midstream Partners LP (Noble Midstream Partners) lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact Noble Midstream Partners' economic performance; therefore, Noble Midstream Partners is considered a 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 Interests In third quarter 2016, Noble Midstream Partners, a subsidiary of Noble Energy, completed its initial public offering of common units. As a result, we present our consolidated financial statements with a noncontrolling interest section representing the public's ownership in Noble Midstream Partners. We also present third-party ownership in Noble Midstream Partners' consolidated non-wholly owned subsidiaries as noncontrolling interests. See Note 5. Acquisitions and Divestitures. Equity Method of AccountingWe use the equity method of accounting for investments in entities that we do not control but over which we exert significant influence. Our equity investees own and operate various midstream assets which we consider an essential component of our business and a necessary and integral element to our value chain involving the monetization of natural gas. With our partners, we engage in joint strategic operational and financial decision making for these entities.
In order to reflect the economics associated with our integrated upstream value chain described above, we include income from equity method investees as a component of revenues in our consolidated statements of operations.
We carry equity method investments at our share of net assets of the equity investees plus loans and advances, and include the investments in other noncurrent assets inon our consolidated balance sheets. Within our consolidated statements of cash flows, activity is reflected within cash flows provided by operating activities and cash flows provided by (used in)used in investing activities. Differences in the basis of the investment and the separate net asset value of the investee, if any, are amortized into income over the remaining useful life of the underlying assets. Our share of income taxes incurred directly by the equity method investees is reported in income from equity method investees and is not included in our income tax provision in our consolidated statements of operations. See Note 7.15. Equity Method Investments. Noncontrolling Interests In third quarter 2016, Noble Midstream Partners LP (Noble Midstream Partners), a subsidiary of Noble Energy, completed its initial public offering of common units. As a result, we present our consolidated financial statements with a noncontrolling interest section representing the public's ownership in Noble Midstream Partners. See Note 16. Additional Shareholders' Equity Information.Consolidated VIE Noble Energy has determined that the partners with equity at risk in Noble Midstream Partners lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact Noble Midstream Partners' economic performance; therefore, Noble Midstream Partners is considered a variable interest entity (VIE). Through Noble Energy's ownership interest in Noble Midstream GP LLC (the General Partner to Noble Midstream Partners), Noble Energy has the authority to direct the activities that most significantly affect economic performance and the obligation to absorb losses or the right to receive benefits that could be potentially significant to Noble Midstream Partners. Therefore, Noble EnergyForeign CurrencyThe US dollar is considered the primary beneficiaryfunctional currency for each of our international operations. Transactions that are completed in foreign currencies are remeasured into US dollars and consolidates Noble Midstream Partners.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 EstimatesThe 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 and NGL reserves are the most significant of our estimates. All 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, NGLs and natural gas and NGLs.gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil, NGL and natural gas and NGL reserves. The accuracy of any reserves estimate is a function of the quality
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| 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 and NGLs that are ultimately recovered. Qualified petroleum engineers in our Houston and Denver offices prepare all reserves estimates for our different geographical regions. These reserves estimates are reviewed and approved by senior engineering staff and division management with final approval by the Senior Vice President – Corporate Development and certain members of senior management. See Supplemental Oil and Gas Information (Unaudited). Other items subject to estimates and assumptions include the carrying amounts of inventory, property, plant and equipment, goodwill, exit costs and asset retirement obligations (AROs),AROs, valuation allowances for receivables and deferred income tax assets, and valuation of derivative instruments, among others. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. Declines in
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
commodity prices could result in a reduction in our fair value estimates and cause us to perform analyses to determine if our oil and gas properties are impaired. As future commodity prices cannot be determined accurately, actual results could differ significantly from our estimates.
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.See Supplemental Oil and Gas Information (Unaudited). Reclassifications
In Note 14.3. Segment Information, we report a new Midstream segment, established second quarter 2017, and present prior period amounts on a comparable basis. .Certain other prior-period amounts have been reclassified to conform to the current period presentation.
Fair Value Measurements Fair value measurements are based on a hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three levels. The fair value hierarchy is as follows:
Level 1 measurements are fair value measurements which use quoted market prices (unadjusted) in active markets for identical assets or liabilities.
Level 2 measurements are fair value measurements which use inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly.
Level 3 measurements are fair value measurements which use unobservable inputs.
The fair value hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. We use Level 1 inputs when available, as Level 1 inputs generally provide the most reliable evidence of fair value. See Note 13.14. Fair Value Measurements and Disclosures. Cash and Cash EquivalentsFor 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 AccountsOur accounts receivable result from sales of crude oil, NGL and natural gas production and joint interest billings to our partners for their share of expenses on joint venture projects for which we are the operator. The majority of these receivables have payment terms of 30 days or less. Our accounts receivable reflect a 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 routinely assess the recoverability of all material trade and other receivables to determine their collectibility. We accrue a reserve on a receivable when, based on management’s judgment, it is probable that a receivable will not be collected and the amount of such reserve may be reasonably estimated. See Note 2. Additional Financial Statement Information. InventoriesInventories 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 DD&Adepreciation, depletion and amortization (DD&A) of oil and gas properties. See Note 2. Additional Financial Statement Information. Property, Plant and EquipmentSignificant accounting policies for our property, plant and equipment are as follows:
SuccessfulOil 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 by the unit-of-production method based on proved crude oil, NGL and natural gas and NGL reserves on a field-by-field basis, as estimated by our qualified petroleum engineers. Our policy is to use quarter-end reserves and add back current period production to compute quarterly DD&A expense. Costs of certain gathering facilities or processing plants serving a number of properties or used for third-party processing are depreciated using the straight-line method over the useful lives of the assets ranging from three to thirty years. Upon sale or retirement of depreciable or depletable property, the cost and related
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized. Costs related to repair and maintenance activities are expensed as incurred.
Proved Property Impairment For our proved properties, we routinely assess whether impairment indicators arise during any given quarter and have processes in place to ensure that we become aware of such indicators. Impairment indicators include, but are not limited to, sustained decreases in commodity prices, negative revisions of proved reserves, and increases in development or operating costs. In the event that impairment indicators exist, we conduct an impairment test. To that end,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.
When the carrying amount of a property exceeds its estimated undiscounted future net cash flows, the carrying amount is reduced to estimated fair value. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future crude oil and natural gas production, commodity prices based on published forward commodity price curves or contract prices as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate.
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Other long-lived assets, such as our midstream assets, are evaluated for potential impairment whenever events or changes in circumstances indicate that their carrying value may be greater than the undiscounted future net cash flows. Impairment, if any, is measured as the excess of an asset’s carrying amount over its estimated fair value, which is estimated as described above.
We recorded property impairment charges in 2018, 2017 2016 and 20152016 and it is possible that other proved oil and gas propertiesassets could become impaired in the future due to commodity price declines and/or field performance.future. See Note 5. Asset Impairments14. Fair Value Measurements and Disclosures. Unproved Property ImpairmentOur unproved properties consist of leasehold costs and allocated value to probable and possible reserves resulting from acquisitions. We assess individually significant unproved properties for impairment on a quarterly basis and recognize a loss at the time of impairment by providing an impairment allowance. In determining whether a significant unproved property is impaired, we consider numerous factors including, but not limited to, current exploration plans, favorable or unfavorable exploration activity on the property being evaluated and/or adjacent properties, our geologists' evaluation of the property, and the remaining months in the lease term for the property.
When we have allocated fair value to an unproved property as the result of a transaction accounted for as a business combination, we use a future cash flow analysis to assess the unproved property for impairment. Cash flows used in the impairment analysis are determined based on management’s estimates of crude oil, NGL and natural gas and NGL reserves, future commodity prices and future costs to produce the reserves. Cash flow estimates related to probable and possible reserves are reduced by additional risk-weighting factors. Other individually insignificant unproved properties are amortized on a composite method over an average holding period.
We recorded undeveloped leasehold impairment expense in 2017. It is possible that unproved oil and gas properties, including undeveloped leases, could become impaired in the future if commodity prices decline or if there are changes in exploration plans or the timing and extent of development activities. See Note 6.7. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.Costs.Properties Acquired in Business CombinationsWhen 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 our own estimates of cash flows from the production of crude oil, NGL and natural gas and NGL reserves. We estimate future prices to apply to the estimated reserves quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net cash flows. For the fair value assigned to proved reserves, future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the business combination. To compensate for the inherent risk ofWhen 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 SaleWe occasionally market oil and gas properties for sale. At the end of each reporting period, we evaluate properties being marketed to determine whether any should be reclassified as held for sale. The held-for-sale criteria include: a commitment to a plan to sell; the asset is available for immediate sale; an active program to locate a buyer exists; the sale of the asset is probable and expected to be completed within one year; the asset is being actively marketed for sale; and it is unlikely that significant changes to the plan will be made. If each of these criteria is met, the property is reclassified as held for sale inon our consolidated balance sheets and will be valued at the lower of net book value or anticipated sales proceeds less costs to sell. Impairment expense would be recorded for any excess of net book value over anticipated sales proceeds less costs to sell. See Note 4. Acquisitions, Divestitures and Merger. Exploration Costs Geological and geophysical costs, delay rentals, amortization of unproved leasehold costs, and costs to drill exploratory wells that do not find proved reserves are expensed as oil and gas exploration. We carry the costs of an exploratory well as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as we are making sufficient progress assessing the reserves and the economic and operating viability of the project. For certain capital-intensive Gulf of Mexico or international projects, it may take us more than one year to evaluate the future potential of the exploratory well
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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, and access to such 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 6.7. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs. Property, Plant and Equipment, Other PropertyOther property includes automobiles, trucks, airplanes, office furniture, computer equipment, buildings, leasehold improvements and other fixed assets such as buildings and leasehold improvements.assets. These items are recorded at cost and are depreciated onusing the straight-line method based on expected lives of the individual assets or group of assets, which rangeranging from three to thirty years. Other
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
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 facility (Revolving Credit Facility)facilities and bonds. 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, and $144 million in 2015.2016.
Asset Retirement ObligationsAROsAsset Retirement Obligations (AROs) consist of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. We recognize the fair value of a liability for an ARO in the period in which it is incurred when we have an existing legal obligation associated with the retirement of our oil and gas properties that can reasonably be estimated, with theestimated. The associated asset retirement cost is capitalized as part of the carrying costvalue of the oil and gas asset. The asset retirement cost is recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at our credit-adjusted risk-free rate. After initial recording, the liability is increased for the passage of time, with the increase being reflected as accretion expense and included in DD&A expense in the consolidated statements of operations. Subsequent adjustments in the cost estimate are reflected in the liability and the amounts continue to be amortized over the useful life of the related long-lived asset. See Note 9.8. Asset Retirement Obligations. Goodwill
2017 Goodwill As of December 31, 2017, our consolidated balance sheet includes goodwill of $1.3 billion. This goodwill resulted from the acquisition (Clayton Williams Energy Acquisition) of Clayton Williams Energy, Inc. (Clayton Williams Energy) completed on April 24, 2017, and represents the excess of the consideration paid for Clayton Williams Energy over the net amounts assigned to identifiable assets acquired and liabilities assumed. All of our recorded goodwill is assigned to the Texas reporting unit, a component of our US reportable and operating segment. See Note 3. Clayton Williams Energy Acquisition.Goodwill is not amortized to earnings but is qualitatively assessed for impairment. We assess goodwill for impairment annually duringat the third quarter,reporting unit level on an annual basis, or more frequently as circumstances require, at the reporting unit level.require. We use qualitative and quantitative assessments to determine whether goodwill is impaired. If based on our qualitative procedures, it is more likely than not that the fair value of the reporting unit is less than its carrying amount, we perform the two-step goodwill impairment test. The two-step goodwill impairment test is also performed whenever events or changes in circumstances indicate that the carrying value may not be recoverable. It is possible that goodwill could become impaired in the future if commodity prices or other economic factors decline. See Recently Issued Accounting Standards – Intangibles – Goodwill and Other: Simplifying the Test for Goodwill Impairment, below, for recently issued accounting guidance regarding future goodwill impairment testing.
We conducted a qualitative goodwill impairment assessment as of September 30, 2017 by examining relevant events and circumstances which could have a negative impact on our goodwill such as: macroeconomic conditions as pertinent to current and expected regulations, industry and market conditions, including overall global and regional supply and demand and impact of such on commodity prices; as well as microeconomic factors relevant to the enterprise such as cost factors that have a negative effect on earnings and cash flows, overall financial performance, reporting unit dispositions, acquisitions, portfolio restructuring and other decisions / circumstances specific to the entity and the reporting unit containing goodwill.
Certain negative indicators as of September 30 2017 included the current onshore service cost inflation resulting in pressure on operating margins impacting our financial results associated with the Texas reporting unit and our stock price. However, we in turn also noted positive indicators such as the current commodity price environment, our current and future drilling and development plans for the Texas assets and synergies we expect from the Clayton Williams Energy Acquisition driven by our unconventional expertise and position in the adjacent properties, which further increase opportunities to drill longer lateral wells on our combined acreage positions, which would contribute to profitability.
Furthermore, we see value creation to be derived from expected midstream build-out opportunities for the gathering, processing and servicing of future production in the Delaware Basin. Having assessed the totality of such events and circumstances described above, we determined that, while there existed certain negative factors, the overall qualitative assessment did not indicateconclude that it is more likely than not that the fair value of thea reporting unit is less than its carrying value. However, regardless ofamount, an impairment charge is recognized for the outcome ofamount by which the qualitative review, we decided to proceed with Step 1 ofcarrying amount exceeds the impairment test as part offair value.
We conducted our annual review.
goodwill impairment assessment as of September 30, 2018. As
such,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
performed Step 1 ofconcluded 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
impairment test, usedallocated to
identify potential impairment. The result of the Step 1 test indicated that the fair value of the Texas reporting unit
exceededwas 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 carrying value, including goodwill,acquisition of Saddle Butte Rockies Midstream, LLC and therefore,affiliates (collectively, Saddle Butte). We recorded the Texas reporting unit goodwill was not consideredintangible 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 impaired asreceived over the estimated useful life of September 30, 2017.
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
If,the intangible assets, which is currently over periods of seven to 13 years. As of December 31, 2018, the net book value of our intangible assets was $310 million. Amortization expense, which is equivalent to accumulated amortization for 2018, of $30 million is included in
the future, we disposeDD&A expense in our consolidated statements of
a reporting unitoperations and statements of cash flows. Intangible assets with finite useful lives are reviewed for impairment when events or
a portion of a reporting unitchanges in circumstances indicate that
constitutes a business, we will include goodwill associated with that business in the carrying amount of
the business in order to determine the gain or loss on disposal. The amount of goodwill allocated to the carrying amount of a business can significantly impact the amount of gain or loss recognized on the sale of that business. The amount of goodwill tosuch assets may not be
included in that carrying amount will be based on the relative fair value of the business to be disposed ofrecoverable. See Note 5. Acquisitions and the portion of the reporting unit that will be retained.Divestitures.2015 Goodwill At December 31, 2015, we reviewed our goodwill balance of $779 million for impairment inExit Costs In accordance with our accounting policy and identified factors, including continuing declines in commodity prices and the market value of our common stock, indicating that the fair value of goodwill could have fallen below its book value. We determined that the goodwill was fully impaired and recognized a loss of $779 million. This goodwill related primarily to the excess purchase price over amounts assigned to assets acquired and liabilities assumed in the merger of Rosetta Resources Inc. (Rosetta) into a subsidiary of Noble Energy (Rosetta Merger) in 2015 and the Patina Merger in 2005 and was associated with our US reporting unit. During 2015, prior to the impairment, goodwill increased $163 million due to the Rosetta Merger and decreased $4 million due to allocations of goodwill to US onshore properties sold.
For purposes of determining the 2015 goodwill impairment,Accounting Standards Codification (ASC) 420 – Exit or Disposal Cost Obligations, we estimated the implied fair value of the goodwill using a variety of valuation methods, including the income and market approaches. Our estimate of fair value required us to use significant unobservable inputs, representative of a Level 3 fair value measurement, including assumptions for future crude oil and natural gas production, commodity prices based on forward commodity price curves, operating and development costs and other factors. The analysis supported that the implied fair value of goodwill was zero and, as such, goodwill was fully impaired.
Exit Costs We recognize the fair value of a liability for an exit cost in the period in which a liability is incurred. Accrued exit costs at December 31, 2017 relate primarily to estimated costs associated with retained Marcellus Shale firm transportation contracts.
The recognition and fair value estimation of an exit cost liability requirerequires that management take into account certain estimates and assumptions such as: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 the liabilityexit cost liabilities at estimated fair value, based on expected future cash outflows required to satisfy the obligation, net of estimated recoveries, and discounted. 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 be 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 17.10. Marcellus Shale Firm Transportation Commitments and Contingencies. Derivative Instruments and Hedging Activities All derivative instruments (including certain derivative instruments embedded in other contracts) are recorded inon 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 andagainst 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. Derivative Instruments and Hedging Activities. Stock-Based CompensationRestricted stock and stock options issued to employees and directors are recorded on grant-date at grant-date fair value. Expense is recognized on a straight-line basis over the employee’s and director’s requisite service period (generally the vesting period of the award) in the consolidated statements of operations. In 2016, we issued cash-settled awards to certain employees in lieu of a portion of restricted stock and stock options. We recognize the value of cash-settled awards utilizing the liability method as defined under Accounting Standards CodificationASC Topic 718, Compensation – Stock Compensation. The fair value of liability awards is remeasured at each reporting date, based on the fair market value of a share of common stock of the Company as of the reporting date, through the settlement date with the change in fair value recognized as compensation expense over that period. See Note 12.17. Stock-Based and Other Compensation Plans. Pension and Other Postretirement Benefit Plans We recognize the funded status (the difference between the fair value of plan assets and the projected benefit obligation) of restoration and other postretirement benefit plans in the consolidated balance sheets, with a corresponding adjustment to accumulated other comprehensive loss (AOCL), net of tax. The amount remaining in AOCL at December 31, 20172018 represents unrecognized net actuarial loss and unrecognized prior service cost related to our restoration plan. These amounts are currently being recognized as net periodic benefit cost pursuant to our historical accounting
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
policy for amortizing such amounts. Any actuarial gains and losses that arise during the plan year, but which are not required to be recognized as net periodic benefit cost in the same period, are recognized as a component of AOCL. In third quarter 2015, we completed
ContingenciesWe are subject to legal proceedings, claims and liabilities that arise in the processordinary course of terminating our noncontributory, tax-qualified defined benefit pension plan throughbusiness. We accrue for losses associated with legal claims when such losses are considered probable and the purchaseamounts can be reasonably estimated. See Note 11. 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 annuities for the remaining participants. As a result, we reclassified all remaining unamortized prior service cost and actuarial losses relating to the pension plan from AOCL to earnings.loss.
Income Taxes and Impact of Tax Reform LegislationIncomeWe are subject to income and other taxes are accountedin numerous taxing jurisdictions worldwide. For financial reporting purposes, we provide taxes at rates applicable for underthe 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.
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
On December 22, 2017, the US Congress enacted the Tax Cuts and Jobs Act (Tax Reform Legislation), which made significant changes to US federal income tax law affecting us. See Note 11.12. Income Taxes. Treasury Stock We record treasury stock purchases at cost, which includes incremental direct transaction costs.Amounts are recorded as reductions in shareholders’ equity in the consolidated balance sheets.
Revenue Recognition and ImbalancesWe record revenuesrecognize revenue at an amount that reflects the consideration to which we expect to be entitled in exchange for transferring goods or services to a customer, using a five-step process, in accordance with ASC 606 – Revenue from the sales of crude oil, natural gas and NGLs when the product is delivered at a fixed or determinable price, title has transferred and collectibility is reasonably assured.Contracts with Customers. See Note 4. Revenue from Contracts with Customers. Basic and Diluted Earnings (Loss) Per Share Attributable to Noble EnergyBasic 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.
ContingenciesWe are subject to legal proceedings, claims and liabilities that arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are considered probable and the amounts can be reasonably estimated. See Note 17. Commitments and Contingencies.We self-insure the medical and dental coverage provided to certain employees, and the deductibles for workers’ compensation, automobile liability and general liability coverage. Liabilities are accrued for self-insured claims, or when estimated losses exceed coverage limits, and when sufficient information is available to reasonably estimate the amount of the loss.
Foreign 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.
Segment Information Accounting policies for geographical segments are the same as those described above. Transfers between segments are accounted for at market value. We do not consider interest income and expense or income tax benefit or expense in our evaluation of the performance of geographical segments. See Note 14. Segment Information.Revolving Credit FacilitiesIn accordance with our accounting policy, we net intra-quarter revolving credit facility activity to zero for purposes of consolidated statements of cash flows disclosure.
Recently Issued Accounting Standards
Revenue RecognitionLeasesIn May 2014,February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2014-09 (ASU 2014-09), which creates Topic 606, Revenue from Contracts with Customers. In summary, revenue recognition would occur upon the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Additionally, ASU 2014-09 requires enhanced financial statement disclosures over revenue recognition.
We continue to evaluate the impact of ASU 2014-09 on our accounting policies, internal controls, and consolidated financial statements and related disclosures. We are performing a review of contracts for each of our revenue streams and developing accounting policies to address the provisions of ASU 2014-09. ASU 2014-09 also includes provisions regarding future revenues and expenses under a gross-versus-net presentation. We are evaluating the impact, if any, on the presentation of future revenues and expenses under this gross-versus-net presentation guidance. Based upon assessments performed to date, we do not expect
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
ASU 2014-09 to have an effect on the timing of revenue recognition or our financial position. In addition, we expect the impact regarding gross-versus-net presentation to involve certain presentation changes specifically related to domestic natural gas processing revenues and expenses. The impact of such presentation changes will not impact our net income. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. We will adopt the new standard on January 1, 2018, using the modified retrospective approach.
Compensation – Stock Compensation (Topic 718): Scope of Modification Accounting In May 2017, the FASB issued Accounting Standards Update No. 2017-09 (ASU 2017-09) Compensation – Stock Compensation (Topic 718). The purpose of this update is to provide clarity as to which modifications of awards require modification accounting under Topic 718, whereas previously issued guidance frequently resulted in varying interpretations and a diversity of practice. An entity should employ modification accounting unless the following are met: (1) the fair value of the award is the same immediately before and after the award is modified; (2) the vesting conditions are the same under both the modified award and the original award; and (3) the classification of the modified award is the same as the original award, either equity or liability. Regardless of whether modification accounting is utilized, award disclosure requirements under Topic 718 remain unchanged. ASU 2017-09 will be effective for annual or any interim periods beginning after December 15, 2017. We will adopt the new standard on the effective date of January 1, 2018 and do not believe adoption will have a material impact on our financial statements.
Business Combinations – Clarifying the Definition of a Business In January 2017, the FASB issued Accounting Standards Update No. 2017-01 (ASU 2017-01): Business Combinations – Clarifying the Definition of a Business, that assists in determining whether certain transactions should be accounted for as acquisitions or dispositions of assets or businesses. The amendment provides a screen to be applied to the fair value of an acquisition or disposal to evaluate whether the assets in question are simply assets or if they are a business. If the screen is not met, no further evaluation is needed. If the screen is met, certain steps are subsequently taken to make the determination. ASU 2017-01 is designed to reduce the number of transactions accounted for as business transactions, which take more time and cost more to analyze than asset transactions. ASU 2017-01 is effective for annual and interim periods beginning after December 15, 2017 and is required to be applied prospectively. Our recent Clayton Williams Energy Acquisition was not impacted by this guidance, which we will apply to applicable and qualifying transactions after adoption on January 1, 2018.
Statement of Cash Flows – Restricted Cash In November 2016, the FASB issued Accounting Standards Update No. 2016-18 (ASU 2016-18): Statement of Cash Flows – Restricted Cash, which requires amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the total beginning and ending amounts for the periods shown on the statement of cash flows. ASU 2016-18 will be effective for annual and interim periods beginning after December 15, 2017, with earlier application permitted. We will adopt the new standard on the effective date of January 1, 2018 and do not believe adoption will have a material impact on our consolidated statements of cash flows and related disclosures.
Statement of Cash Flows – Classification of Certain Cash Receipts and Cash Payments In August 2016, the FASB issued Accounting Standards Update No. 2016-15 (ASU 2016-15): Statement of Cash Flows – Classification of Certain Cash Receipts and Cash Payments, to clarify how eight specific cash receipt and cash payment transactions should be presented in the statement of cash flows. ASU 2016-15 will be effective for annual and interim periods beginning after December 15, 2017, with earlier application permitted. We will adopt the new standard on the effective date of January 1, 2018 and do not believe adoption will have a material impact on our consolidated statements of cash flows and related disclosures as this update pertains to classification of items and is not a change in accounting principle.
Leases In February 2016, the FASB issued Accounting Standards Update No. 2016-02 (ASU 2016-02): Leases. The guidancestandard requires lessees to recognize assetsa right of use asset (ROU asset) and liabilitieslease liability on the balance sheet for the rights and obligations created by leases with terms of more than 12 months.leases. ASU 2016-02 also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. In July 2018, the FASB issued Accounting Standards Update No. 2018-11 (ASU 2018-11): Leases (Topic 842): Targeted Improvements, which provides for an alternative transition method by allowing entities to initially apply 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 will beis effective for annual and interim periods beginning after December 15, 2018, with earlier application permitted.
In the normal course of business, we enter into capital and operating lease agreements to support our exploration and development operations and lease assets, such as drilling rigs, platforms, storage facilities, field services and well equipment, pipeline capacity, office space and other assets.
We will adoptadopted the new standard on the effective date of January 1, 2019. At2019, using a modified retrospective approach as permitted under ASU 2018-11.
The new standard provides a number of optional practical expedients in transition. We expect to:
elect the package of 'practical expedients', which permits 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 plan to account for existing land easements under our current 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 all of our leases.
We do not expect to elect the hindsight practical expedient in determining the lease term 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 time,standard.
While we cannot reasonably estimateare finalizing our assessment of the impact ASU 2016-02 will have on our consolidated financial statements; however,effect of adoption, we believedo not expect the adoption and implementation of ASU 2016-02this standard will have a material impacteffect on our consolidatedfinancial statements. We estimate the most significant impact will relate to the recognition of new ROU assets and lease liabilities on our balance sheet resulting from an increase in bothfor 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 corresponding ROU assets and liabilities relatingof the same amount based on the present value of the remaining minimum rental payments under current leasing standards for existing operating leases.
Financial Instruments: Credit Losses In June 2016, the FASB issued Accounting Standards Update No. 2016-13 (ASU 2016-13): Financial Instruments – Credit Losses, which replaces the incurred loss impairment methodology with a methodology that reflects expected credit losses. The update is intended to leasing activities. As partprovide financial statement users with more useful information about expected credit losses. The amended standard is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. From evaluation of our assessment to date, we have formed an implementation work team, prepared educational and training materials pertinent to ASU 2016-02 and have begun contract review and documentation.current credit portfolio, which includes receivables for commodity sales,
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
joint interest billings due from partners 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 adoption 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. 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 guidance, an entitystandard, we will perform its annual, or interim,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, with early adoption permitted. We are currently evaluating the provisions ofearly adopted this ASU 2017-04 andin fourth quarter 2018. This adoption did not have not yet determined if we will early adopt.a material impact on our financial statements.
Financial Instruments – Credit LossesAccumulated Other Comprehensive Income In June 2016,February 2018, the FASB issued Accounting Standards Update No. 2016-132018-02 (ASU 2016-13)2018-02): Financial InstrumentsIncome Statement – Credit Losses, which replacesReporting Comprehensive Income to allow reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the incurred loss impairment methodology in current US GAAP with a methodology that reflects expected credit losses. The update is intended to provide financial statement users with more useful information about expected credit losses. The amended guidanceTax Reform Legislation. ASU 2018-02 is effective for fiscal yearsannual and interim periods beginning after December 15, 2019,2018, with early adoption permitted. We will adoptearly adopted this ASU in fourth quarter 2018, reclassifying the new standard on the effective datetax effect of January 1, 2020 and are currently evaluating the effect, if any, that the guidance willapproximately $6 million stranded in accumulated other comprehensive income to retained earnings. This adoption did not have a material impact on our consolidated financial statements and related disclosures.statements.
SAB 118 On December 22, 2017, the SEC staff issued Staff Accounting Bulletin No. 118 (SAB 118) to address the application of US GAAP in situations when a registrant does not have the necessary information available, prepared, or analyzed (including computations) in reasonable detail to complete the accounting for certain income tax effects relating to the Tax Reform Legislation. SAB 118 provides guidance for registrants under three scenarios:
1) if measurement of certain income tax effects is complete, registrants must reflect the tax effects of the Tax Reform Legislation for which the accounting is complete;
2) if measurement of certain income tax effects can be reasonably estimated, registrants must report provisional amounts for those specific income tax effects of the Tax Reform Legislation for which the accounting is incomplete but a reasonable estimate can be determined. Provisional amounts or adjustments to provisional amounts identified in the measurement period, as defined, should be included as an adjustment to tax expense or benefit from continuing operations in the period the amounts are determined; and
3) if measurement of certain income tax effects cannot be reasonably estimated, registrants are not required to report provisional amounts for any specific income tax effects of the Tax Reform Legislation for which a reasonable estimate cannot be determined, and would continue to apply ASC 740 – Income Taxes based on the provisions of the tax laws that were in effect immediately prior to the enactment of the Tax Reform Legislation. Registrants would report the provisional amounts of the tax effects of the Tax Reform Legislation in the first reporting period in which a reasonable estimate can be determined.
The SEC staff believes that in no circumstances should the measurement period extend beyond December 22, 2018, one year from the enactment of the Tax Reform Legislation. See Note 11. Income Taxes.
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Note 2. Additional Financial Statement Information
AdditionalStatements of Operations Information Other statements of operations information is as follows: | | | | | Year Ended December 31, | | Year Ended December 31, |
| (millions) | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| Sales of Purchased Oil and Gas and Other | | | |
| | |
| | |
|
Sales of Purchased Oil and Gas (1) | | | $ | 275 |
| | $ | — |
| | $ | — |
|
| Income from Equity Method Investees | | | 172 |
| | 177 |
| | 102 |
|
| Midstream Services Revenues - Third Party | | | 78 |
| | 19 |
| | — |
|
| Total | | | $ | 525 |
| | $ | 196 |
| | $ | 102 |
|
| Production Expense | | |
| | |
| | |
| | | | | | |
| Lease Operating Expense | | $ | 571 |
| | $ | 542 |
| | $ | 563 |
| | $ | 576 |
| | $ | 571 |
| | $ | 542 |
|
| Production and Ad Valorem Taxes | | 138 |
| | 78 |
| | 127 |
| | 190 |
| | 118 |
| | 57 |
|
Gathering, Transportation and Processing Expense (1) | | 432 |
| | 480 |
| | 306 |
| |
| Gathering, Transportation and Processing Expense | | | 393 |
| | 432 |
| | 480 |
|
| Other Royalty Expense | | | 38 |
| | 20 |
| | 21 |
|
| Total | | $ | 1,141 |
| | $ | 1,100 |
| | $ | 996 |
| | $ | 1,197 |
| | $ | 1,141 |
| | $ | 1,100 |
|
| Exploration Expense | | | | | | | | | | | | |
Leasehold Impairment and Amortization (2) | | $ | 62 |
| | $ | 148 |
| | $ | 113 |
| |
| Leasehold Impairment and Amortization | | | $ | 1 |
| | $ | 62 |
| | $ | 148 |
|
| Dry Hole Cost | | 9 |
| | 579 |
| | 266 |
| | 1 |
| | 9 |
| | 579 |
|
| Seismic, Geological and Geophysical | | 27 |
| | 76 |
| | 34 |
| | 22 |
| | 27 |
| | 76 |
|
| Staff Expense | | 55 |
| | 77 |
| | 43 |
| | 54 |
| | 55 |
| | 77 |
|
| Other | | 35 |
| | 45 |
| | 32 |
| | 51 |
| | 35 |
| | 45 |
|
| Total | | $ | 188 |
| | $ | 925 |
| | $ | 488 |
| | $ | 129 |
| | $ | 188 |
| | $ | 925 |
|
| Loss on Marcellus Shale Upstream Divestiture | | | | | | | |
| Loss on Marcellus Shale Upstream Divestiture and Other | | | | | | | |
| Loss on Sale | | $ | 2,270 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 2,270 |
| | $ | — |
|
Firm Transportation Commitment (2) | | 93 |
| | — |
| | — |
| |
Other(3) | | 16 |
| | — |
| | — |
| |
| Exit Cost | | | — |
| | 93 |
| | — |
|
| Other | | | — |
| | 16 |
| | — |
|
| Total | | $ | 2,379 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 2,379 |
| | $ | — |
|
| Other Operating (Income) Expense, Net | | |
| | |
| | |
| |
Marketing Expense (4) | | $ | 47 |
| | $ | 58 |
| | $ | 33 |
| |
Clayton Williams Acquisition Expenses (5) | | 100 |
| | — |
| | — |
| |
Corporate Restructuring Expense (6) | | — |
| | 8 |
| | 51 |
| |
Pension Plan Expense (7) | | — |
| | — |
| | 88 |
| |
Impact of Rosetta Merger (8) | | — |
| | (25 | ) | | 81 |
| |
North Sea Remediation Project Revision (9) | | (42 | ) | | — |
| | — |
| |
Loss on Asset Due to Terminated Contract (10) | | — |
| | 41 |
| | — |
| |
Gain on Divestitures, Net (11) | | (326 | ) | | (238 | ) | | — |
| |
| Other Operating Expense, Net | | | |
| | |
| | |
|
Marketing Expense (2) | | | $ | 40 |
| | $ | 47 |
| | $ | 58 |
|
Cost of Purchased Oil and Gas (1) | | | 296 |
| | — |
| | — |
|
| Clayton Williams Energy Acquisition Expenses | | | — |
| | 100 |
| | — |
|
Gain on Asset Retirement Obligation Revisions (3) | | | (25 | ) | | (42 | ) | | — |
|
| Other, Net | | 33 |
| | 53 |
| | 79 |
| | 35 |
| | 33 |
| | 77 |
|
| Total | | $ | (188 | ) | | $ | (103 | ) | | $ | 332 |
| | $ | 346 |
| | $ | 138 |
| | $ | 135 |
|
| |
(1) | CertainAs 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 gatheringmitigation efforts to utilize capacity and processing expenses were historically presented as components of other operating expense, net, inreduce our consolidated statement of operations. Beginning in 2017, we changed our presentation to reflect these as components of production expense. These costs are now included within gathering, transportationfinancial commitment. See Note 3. Segment Information and processing expense. For the years ended December 31, 2016 and 2015, these costs totaled $17 million and $17 million, respectively, and have been reclassified from other operating expense, net to conform to current presentation. |
| |
(2)
| See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs10. Marcellus Shale Firm Transportation Commitments. |
| |
(3)(2)
| Expense relatesAmounts relate to unutilizedshortfalls in transporting or processing minimum volumes under certain financial commitments associated withprimarily in the DJ Basin for 2018 and in the DJ Basin and Marcellus Shale firm transportation contracts. See Note 17. Commitmentsfor 2017 (prior to the Marcellus Shale upstream divestiture) and Contingencies. |
| |
(4)(3)
| Amount includes costs for legal and advisory services and employee severance charges. |
| |
(5)
| Expense relates to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments. |
| |
(6)
| Gains due to downward ARO revisions in locations where we have no remaining assets. See Note 3. Clayton Williams Energy Acquisition. |
| |
(7)
| Expenses are associated with corporate organizational activities. |
| |
(8)
| Amount includes reclassification of the actuarial loss from AOCL related to the re-measurement and termination of our defined benefit pension plan to net income (loss). |
| |
(9)
| Amounts represent a purchase price allocation adjustment in 2016 and merger expenses in 2015. See Note 4. Acquisitions, Divestitures and Merger. |
| |
(10)
| See Note 9.8. Asset Retirement Obligations. |
| |
(11)
| Amount relates to the termination of a rig contract offshore Falkland Islands as a result of a supplier's non-performance. |
| |
(12)
| See Note 4. Acquisitions, Divestitures and Merger. |
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
AdditionalBalance Sheet Information Other balance sheet information is as follows: |
| | | | | | | | |
| | | December 31, |
| (millions) | | 2018 | | 2017 |
| Accounts Receivable, Net | | | | |
| Commodity Sales | | $ | 383 |
| | $ | 455 |
|
Joint Interest Billings (1) | | 137 |
| | 207 |
|
| Other | | 111 |
| | 103 |
|
| Allowance for Doubtful Accounts | | (15 | ) | | (17 | ) |
| Total | | $ | 616 |
| | $ | 748 |
|
| Other Current Assets | | |
| | |
|
| Commodity Derivative Assets | | $ | 180 |
| | $ | — |
|
| Inventories, Materials and Supplies | | 55 |
| | 66 |
|
| 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 |
|
| Total | | $ | 418 |
| | $ | 780 |
|
| Other Noncurrent Assets | | | | |
| Equity Method Investments | | $ | 286 |
| | $ | 305 |
|
Customer-Related Intangible Assets, Net (4) | | 310 |
| | — |
|
| Mutual Fund Investments | | 38 |
| | 57 |
|
| Net Deferred Income Tax Asset | | 21 |
| | 25 |
|
| Other Assets, Noncurrent | | 76 |
| | 74 |
|
| Total | | $ | 731 |
| | $ | 461 |
|
| Other Current Liabilities | | | | |
| Production and Ad Valorem Taxes | | $ | 103 |
| | $ | 84 |
|
| Commodity Derivative Liabilities | | 1 |
| | 58 |
|
| Income Taxes Payable | | 22 |
| | 18 |
|
| Asset Retirement Obligations | | 118 |
| | 51 |
|
| Interest Payable | | 66 |
| | 67 |
|
| Current Portion of Capital Lease Obligations | | 41 |
| | 61 |
|
Liabilities Associated with Assets Held for Sale (2) | | 1 |
| | 55 |
|
| Compensation and Benefits Payable | | 83 |
| | 98 |
|
| Other Liabilities, Current | | 84 |
| | 86 |
|
| Total | | $ | 519 |
| | $ | 578 |
|
| Other Noncurrent Liabilities | | | | |
| Deferred Compensation Liabilities | | $ | 147 |
| | $ | 197 |
|
Asset Retirement Obligations | | 762 |
| | 824 |
|
| Marcellus Shale Exit Cost Accrual | | 67 |
| | 76 |
|
| Production and Ad Valorem Taxes | | 83 |
| | 69 |
|
| Commodity Derivative Liabilities | | 26 |
| | 15 |
|
| Other Liabilities, Noncurrent | | 80 |
| | 64 |
|
| Total | | $ | 1,165 |
| | $ | 1,245 |
|
|
| | | | | | | | |
| | | December 31, |
| (millions) | | 2017 | | 2016 |
| Accounts Receivable, Net | | | | |
| Commodity Sales | | $ | 455 |
| | $ | 403 |
|
| Joint Interest Billings | | 207 |
| | 106 |
|
Proceeds Receivable (1) | | — |
| | 40 |
|
| Other | | 103 |
| | 86 |
|
| Allowance for Doubtful Accounts | | (17 | ) | | (20 | ) |
| Total | | $ | 748 |
| | $ | 615 |
|
| Other Current Assets | | |
| | |
|
| Inventories, Materials and Supplies | | $ | 66 |
| | $ | 71 |
|
| Inventories, Crude Oil | | 16 |
| | 18 |
|
Assets Held for Sale(2) | | 629 |
| | 18 |
|
Restricted Cash (3) | | 38 |
| | 30 |
|
| Prepaid Expenses and Other Assets, Current | | 31 |
| | 23 |
|
| Total | | $ | 780 |
| | $ | 160 |
|
| Other Noncurrent Assets | | | | |
| Equity Method Investments | | $ | 305 |
| | $ | 400 |
|
| Mutual Fund Investments | | 57 |
| | 71 |
|
| Net Deferred Income Tax Asset | | 25 |
| | — |
|
| Other Assets, Noncurrent | | 74 |
| | 37 |
|
| Total | | $ | 461 |
| | $ | 508 |
|
| Other Current Liabilities | | | | |
| Production and Ad Valorem Taxes | | $ | 84 |
| | $ | 115 |
|
| Commodity Derivative Liabilities, Current | | 58 |
| | 102 |
|
| Income Taxes Payable | | 18 |
| | 53 |
|
| Asset Retirement Obligations, Current | | 51 |
| | 160 |
|
| Interest Payable | | 67 |
| | 76 |
|
| Compensation and Benefits Payable | | 98 |
| | 110 |
|
| Current Portion of Capital Lease and Other Obligations | | 61 |
| | 63 |
|
| Other Liabilities, Current | | 141 |
| | 63 |
|
| Total | | $ | 578 |
| | $ | 742 |
|
| Other Noncurrent Liabilities | | | | |
| Deferred Compensation Liabilities, Noncurrent | | $ | 197 |
| | $ | 218 |
|
| Asset Retirement Obligations, Noncurrent | | 824 |
| | 775 |
|
| Production and Ad Valorem Taxes | | 69 |
| | 47 |
|
Marcellus Firm Transportation Commitment, Noncurrent (4) | | 76 |
| | — |
|
| Other Liabilities, Noncurrent | | 79 |
| | 63 |
|
| Total | | $ | 1,245 |
| | $ | 1,103 |
|
| |
(1) | We bill partners for their share of expenses of joint venture projects for which we are the operator. These projects, especially those 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. |
| |
(2) | Proceeds relate to the farm-out of a 35% interest Assets held for sale at December 31, 2018 include certain proved and unproved non-core acreagein Block 12 offshore Cyprus and were received in January 2017. See Note 4. Acquisitions, Divestitures and Merger. |
(2) 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, |
| (millions) | | 2018 | | 2017 |
| Cash and Cash Equivalents at Beginning of Period | | $ | 675 |
| | $ | 1,180 |
|
| Restricted Cash at Beginning of Period | | 38 |
| | 30 |
|
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | | $ | 713 |
| | $ | 1,210 |
|
| Cash and Cash Equivalents at End of Period | | $ | 716 |
| | $ | 675 |
|
| Restricted Cash at End of Period | | 3 |
| | 38 |
|
| Cash, Cash Equivalents, and Restricted Cash at End of Period | | $ | 719 |
| | $ | 713 |
|
A significant portion of our cash is located in foreign subsidiaries. The cash is denominated in US dollars and invested in highly liquid money market funds and short term deposits with original maturities of three months or less at the time of purchase. Although our cash and cash equivalents are deposited with major international banks and financial institutions, concentrations of cash in certain foreign locations may increase credit risk. We monitor the creditworthiness of the banks and financial institutions with which we invest and review the securities underlying our investment accounts. We believe that losses from nonperformance are unlikely to occur; however, we are not able to predict sudden changes in creditworthiness.
Supplemental statements of cash flow information are as follows: |
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| (millions) | | 2018 |
| 2017 |
| 2016 |
| Cash Paid During the Year For | | | | | | |
| Interest, Net of Amount Capitalized | | $ | 270 |
| | $ | 346 |
| | $ | 327 |
|
| Income Taxes Paid, Net | | 172 |
| | 121 |
| | 236 |
|
| Non-Cash Financing and Investing Activities | | | | | | |
| Increase in Capital Lease Obligations | | 14 |
| | — |
| | 5 |
|
Note 3. Segment Information
We have the following reportable segments: United States (US onshore and Gulf of Mexico (until April 2018)); Eastern Mediterranean (Israel and Cyprus); West Africa (Equatorial Guinea, Cameroon and Gabon); Other International (Suriname, Falkland Islands, Canada, 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.
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, the chief operating decision maker analyzes income (loss) before income taxes. Management believes income (loss) before income taxes provides information useful in assessing the Company's operating and financial performance across periods.
Expenses related to debt, 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.
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| 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 |
| Year Ended December 31, 2018 |
| Crude Oil Sales | $ | 2,945 |
| | $ | 2,548 |
| | $ | 7 |
| | $ | 390 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| NGL Sales | 587 |
| | 587 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Natural Gas Sales | 929 |
| | 435 |
| | 473 |
| | 21 |
| | — |
| | — |
| | — |
| | — |
|
| Total Crude Oil, NGL and Natural Gas Sales | 4,461 |
| | 3,570 |
| | 480 |
| | 411 |
| | — |
| | — |
| | — |
| | — |
|
| Sales of Purchased Oil and Gas | 275 |
| | 20 |
| | — |
| | — |
| | — |
| | 142 |
| | — |
| | 113 |
|
| Income from Equity Method Investees | 172 |
| | — |
| | — |
| | 132 |
| | — |
| | 40 |
| | — |
| | — |
|
| Midstream Services Revenues - Third Party | 78 |
| | — |
| | — |
| | — |
| | — |
| | 78 |
| | — |
| | — |
|
| Intersegment Revenues | — |
| |
|
| |
|
| |
|
| |
|
| | 351 |
| | (351 | ) | |
|
|
| Total Revenues | 4,986 |
| | 3,590 |
| | 480 |
| | 543 |
| | — |
| | 611 |
| | (351 | ) | | 113 |
|
| Lease Operating Expense | 576 |
| | 480 |
| | 26 |
| | 97 |
| | — |
| | — |
| | (27 | ) | | — |
|
| Production and Ad Valorem Taxes | 190 |
| | 184 |
| | — |
| | — |
| | — |
| | 6 |
| | — |
| | — |
|
| Gathering, Transportation and Processing Expense | 393 |
| | 533 |
| | — |
| | — |
| | — |
| | 95 |
| | (235 | ) | | — |
|
| Other Royalty Expense | 38 |
| | 38 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total Production Expense | 1,197 |
| | 1,235 |
| | 26 |
| | 97 |
| | — |
| | 101 |
| | (262 | ) | | — |
|
| Exploration Expense | 129 |
| | 48 |
| | 7 |
| | 6 |
| | 68 |
| | — |
| | — |
| | — |
|
| DD&A | 1,934 |
| | 1,642 |
| | 60 |
| | 115 |
| | 2 |
| | 87 |
| | (20 | ) | | 48 |
|
| (Gain) Loss on Divestitures, Net | (843 | ) | | 36 |
| | (376 | ) | | — |
| | — |
| | (503 | ) | | — |
| | — |
|
| Asset Impairments | 206 |
| | 169 |
| | — |
| | — |
| | — |
| | 37 |
| | — |
| | — |
|
| Goodwill Impairment | 1,281 |
| | 1,281 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Cost of Purchased Oil and Gas | 296 |
| | 20 |
| | — |
| | — |
| | — |
| | 136 |
| | — |
| | 140 |
|
| Gain on Asset Retirement Obligation Revisions | (25 | ) | | — |
| | (8 | ) | | — |
| | (17 | ) | | — |
| | — |
| | — |
|
| (Gain) Loss on Commodity Derivative Instruments | (63 | ) | | (70 | ) | | — |
| | 7 |
| | — |
| | — |
| | — |
| | — |
|
| Income (Loss) Before Income Taxes | 140 |
| | (875 | ) | | 742 |
| | 305 |
| | (53 | ) | | 726 |
| | (60 | ) | | (645 | ) |
| Additions to Long Lived Assets | 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 |
|
| Year Ended December 31, 2017 |
| Crude Oil Sales | $ | 2,346 |
| | $ | 1,993 |
| | $ | 6 |
| | $ | 347 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| NGL Sales | 493 |
| | 493 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Natural Gas Sales | 1,221 |
| | 670 |
| | 528 |
| | 23 |
| | — |
| | — |
| | — |
| | — |
|
| Total Crude Oil, NGL and Natural Gas Sales | 4,060 |
| | 3,156 |
| | 534 |
| | 370 |
| | — |
| | — |
| | — |
| | — |
|
| Income from Equity Method Investees | 177 |
| | — |
| | — |
| | 120 |
| | — |
| | 57 |
| | — |
| | — |
|
| Midstream Services Revenues - Third Party | 19 |
| | — |
| | — |
| | — |
| | — |
| | 19 |
| | — |
| | — |
|
| Intersegment Revenues | — |
| | — |
| | — |
| | — |
| | — |
| | 277 |
| | (277 | ) | | — |
|
| Total Revenues | 4,256 |
| | 3,156 |
| | 534 |
| | 490 |
| | — |
| | 353 |
| | (277 | ) | | — |
|
|
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| 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 | | |
| (millions) | 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 |
| | — |
| | — |
| | — |
| | — |
|
| (Loss) Income Before Income Taxes | (1,772 | ) | | (1,277 | ) | | 543 |
| | (338 | ) | | (199 | ) | | 176 |
| | (51 | ) | | (626 | ) |
| Additions to Long Lived Assets | 1,526 |
| | 1,353 |
| | 88 |
| | 54 |
| | (6 | ) | | 58 |
| | (53 | ) | | 32 |
|
| Property, Plant and Equipment, Net | 18,548 |
| | 14,755 |
| | 1,872 |
| | 980 |
| | 15 |
| | 594 |
| | — |
| | 332 |
|
| |
(1) | Intersegment eliminations related to income (loss) before income taxes are the result of Midstream expenditures. These costs are presented as property, plant and equipment within the E&P business on an unconsolidated basis, in accordance with the successful efforts method of accounting, and are eliminated upon consolidation. |
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.
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| | |
| 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
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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. |
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| (millions) | 2019 | 2020 | Total |
Natural Gas Revenues (1) | $ | 137 |
| $ | 169 |
| $ | 306 |
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(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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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. Acquisitions and Divestitures
We maintain an ongoing portfolio management program and have engaged in various transactions over recent years.
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 sell 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, 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 received net proceeds of $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.
Divestiture of 7.5% Interest in Tamar Field On March 14, 2018, we closed the sale of 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 and 38.5 million shares of Tamar Petroleum 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% lower 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 of Tamar Petroleum 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 of our investment in Southwest Royalties, Inc. (Southwest Royalties), a subsidiary of Clayton Williams Energy, Inc. (Clayton Williams Energy), which we acquired in the acquisition of Clayton Williams Energy (Clayton Williams Energy Acquisition) in 2017. We received proceeds of $60 million, resulting in no 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 of assets in the Greeley Crescent area of the DJ Basin a 7.5% interestand received proceeds of $68 million, resulting in no gain or loss recognition on the sale of these assets.
Divestiture of Non-Core Delaware Basin Acreage In December 2018, we closed the sale of certain non-core acreage in the Tamar and Dalit fields, offshore Israel, certain non-strategic assets acquired in the Clayton Williams Energy Acquisition and the CONE investments. Assets held for sale at December 31, 2016 include assets in the Greeley Crescent area of the DJ Basin. See Note 4. Acquisitions, Divestitures and Merger. (3) Balance at December 31, 2017 represents amount held in escrow for the purchase of a midstream entity. Balance at December 31, 2016 represents amount held in escrow for the purchase of certain Delaware Basin, properties. See Note 4. Acquisitions, Divestitures and Merger.receiving proceeds of $63 million, resulting in a pre-tax loss of $16 million. | |
(4)
| Relates to unutilized commitments associated with Marcellus Shale firm transportation contracts. See Note 4. Acquisitions, Divestitures |
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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 Merger.Wells Ranch positions in exchange for approximately 12,300 net undeveloped acres in non-core areas of Mustang and Wells Ranch. No gain or loss was recognized.
Noble Midstream Partners Saddle Butte Acquisition On January 31, 2018, Noble Midstream Partners acquired a 54.4% 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.
Supplemental statementsConsideration totaled $681 million, which included $663 million of cash flow informationand assumption of $18 million of liabilities. Greenfield funded approximately $343 million of the purchase price, which is reflected as follows:a contribution from noncontrolling interest within our consolidated statement of 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. |
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| | | Year Ended December 31, |
| (millions) | | 2017 | | 2016 | | 2015 |
| Cash Paid During the Year For | | | | | | |
| Interest, Net of Amount Capitalized | | $ | 346 |
| | $ | 327 |
| | $ | 260 |
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| Income Taxes Paid, Net | | 121 |
| | 236 |
| | 202 |
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| Non-Cash Financing and Investing Activities | | | | | | |
| Increase in Capital Lease and Other Obligations | | — |
| | 5 |
| | 55 |
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Note 3. Clayton Williams Energy Acquisition
In January 2017,Other Acquisitions and Divestitures During 2018, we announced the Clayton Williams Energy Acquisition, which was approved by Clayton Williams Energy stockholders and closed on April 24, 2017. Acquired assets include 71,000 highly contiguous net acres in the core of the Delaware Basin adjacent to our Reeves County holdings in Texas, and an additional 100,000 net acres in other areas of the United States. In total, the acquisition increased our Delaware Basin position toof 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 117,000 net acres.
See Supplemental Oil and Gas Information (Unaudited), below for discussion of proved reserves acquired. In addition, upon closing of the acquisition, approximately 64,00013,000 net acres in Reeves County, TexasTexas. 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 dedicated toconsidered 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 infield crude oil, natural gas and produced water gathering.which closing is anticipated to occur later in first quarter 2019, subject to certain conditions precedent.
Year Ended December 31, 2017
Clayton Williams Energy Acquisition On April 24, 2017, we completed the Clayton Williams Energy Acquisition. Clayton Williams Energy's results of operations since the acquisition date are included in our consolidated statement of operations. The acquisition was effected through the issuance of approximately 56 million shares of Noble Energy common stock with a fair value of approximately $1.9 billion and cash consideration of $637 million, for total consideration of approximately $2.5 billion, in exchange for all outstanding Clayton Williams Energy shares, including stock options, restricted stock awards and warrants.
The closing price of our stock on the New York Stock Exchange (NYSE) was $34.17 on April 24, 2017. In connection with the transaction, we borrowed $1.3 billion under our Revolving Credit Facility (defined below) to fund the cash portion of the acquisition consideration, redeem outstanding Clayton Williams Energy debt, pay associated make-whole premiums and pay related fees and expenses. See Note 10.9. 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 Clayton Williams Energy Acquisition,acquisition, we have incurred acquisition-related costs of $100 million, to date, including $64 million of severance, consulting, investment, advisory, legal and other merger-related fees and $36 million of noncash share-based compensation expense, all of which were expensed and are included in other operating expense, net in our consolidated statements of operations. In addition, we received approximately 720,000 shares of common stock from Clayton Williams Energy shareholders for the payment of withholding taxes due on the vesting of their restricted stock and options pursuant to the purchase and sale agreement, resulting in a $25 million increase in our treasury stock balance.
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Purchase Price Allocation The transaction has beenwas accounted for as a business combination using the acquisition method. The following table represents the preliminary allocation of the total purchase price of Clayton Williams Energy to the assets acquired and the liabilities assumed based on the fair value at the acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill.
Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, analysis of the underlying tax basis of Clayton Williams Energy's assets and liabilities, and final appraisals of assets acquired and liabilities assumed. We expect to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the value of the assets and liabilities, including any goodwill, may be revised as appropriate.
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The following table sets forth our preliminary purchase price allocation: | | | (millions, except per share amounts) | | |
| Fair Value of Common Stock Issued | $ | 1,876 |
| $ | 1,851 |
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| Plus: Cash Consideration Paid to Clayton Williams Energy Stockholders | 637 |
| 637 |
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| Total Purchase Price | $ | 2,513 |
| $ | 2,488 |
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| Plus Liabilities Assumed by Noble Energy: | | |
| Accounts Payable | 99 |
| 99 |
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| Other Current Liabilities | 38 |
| 38 |
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| Long-Term Deferred Tax Liability | 509 |
| 515 |
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| Long-Term Debt | 595 |
| 595 |
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| Asset Retirement Obligations | 63 |
| 63 |
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| Total Purchase Price Plus Liabilities Assumed | $ | 3,817 |
| $ | 3,798 |
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The fair values of Clayton Williams Energy's identifiable assets are as follows: | | | (millions) | | |
| Cash and Cash Equivalents | $ | 21 |
| $ | 21 |
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| Other Current Assets | 70 |
| 70 |
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| Oil and Gas Properties: | | |
| Proved Reserves | 722 |
| 722 |
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| Undeveloped Leasehold Cost | 1,571 |
| 1,571 |
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| Gathering and Processing Assets | 48 |
| 48 |
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| Asset Retirement Costs | 63 |
| 63 |
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| Other Property Plant and Equipment | 12 |
| 12 |
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Implied Goodwill | 1,310 |
| 1,291 |
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| Total Asset Value | $ | 3,817 |
| $ | 3,798 |
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(1) The goodwill, which was associated with the Texas reporting unit included within our oil and gas exploration and production segment, was fully impaired as of December 31, 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 asset retirement obligationsAROs are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligationsAROs were measured using valuation techniques that convert expected future cash flows to a single discounted amount. Significant inputs to the valuation of crude oil and natural gas properties included estimates of: (i) proved, possible and probable reserves; (ii) production rates and related development timing; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average cost of capital rate. These inputs required significant judgments and estimates by management at the time of the valuation and are the most sensitive and may be subject to change.
Based upon the preliminary purchase price allocation, we have recognized $1.3 billion of goodwill, all of which is assigned to the Texas reporting unit. As a result of the acquisition, we expect to realize certain synergies which may result from our control of the combined assets as well as future midstream opportunities. The oil-rich geology of these assets, coupled with our unconventional expertise and position in the adjacent properties, significantly enhances our crude oil focus and growth outlook. The acquisition provides for synergies related to administrative and capital efficiencies, and increased opportunities to drill longer lateral wells on our combined acreage positions, enhances our crude oil production base and future crude oil growth potential. It also adds to our midstream assets and provides future midstream build-out opportunities for the gathering, processing and servicing of future production in the basin.
Results of Operations The results of operations attributable to Clayton Williams Energy are included in our consolidated statements of operations beginning on April 24, 2017. We generated revenues of $99 million and a pre-tax loss of $19 million from the Clayton Williams Energy assets during the period April 24, 2017 to December 31, 2017.
Pro Forma Financial 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
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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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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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| (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 | ) |
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| (millions, except per share amounts) | 2017 | | 2016 |
| Revenues | $ | 4,304 |
| | $ | 3,651 |
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| Net Loss and Comprehensive Loss Attributable to Noble Energy | (678 | ) | | (1,082 | ) |
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| Net Loss Attributable to Noble Energy per Common Share | | | |
| Basic and Diluted | $ | (1.39 | ) | | $ | (2.23 | ) |
Note 4. Acquisitions, Divestitures and Merger
We maintain an ongoing portfolio management program and have engaged in various transactions over recent years.
Year Ended December 31, 2017
Marcellus Shale Upstream Divestiture On June 28, 2017, we closed the sale of all of our Marcellus Shale upstream assets, which were primarily natural gas properties. The sales price totaled $1.2 billion, and we received $1.0 billion of net cash proceeds, after consideration of customary adjustments, at closing.closing adjustments. The sales price includes additional contingent consideration of up to $100 million structured as three separate payments of $33.3 million each. The contingent payments are in effect should the average annual price of the Appalachia Dominion, South Point index exceed $3.30 per MMBtu in the individual annual periods from 2018 through 2020. To date, conditions for the recognition of the contingent consideration are not probable and, therefore, noNo amounts have been accrued related to the contingent consideration. Proceeds from the transaction were used to repay borrowings resulting from the Clayton Williams Energy Acquisition. See Note 10.9. Long-Term Debt. For the year ended December 31, 2017, we recognized a total loss on divestiture of $2.4$2.3 billion, or $1.5 billion after-tax, on this divestiture.after-tax. The aggregate net book value of the properties sold was approximately $3.4 billion, which included approximately $883 million of undeveloped leasehold cost.
As part of the loss, we accrued non-cash exit costs of $41 million, discounted, relating to a retained transportation contract that is currently in service; however, we no longer have production to satisfy this commitment and do not plan to utilize this capacity in the future. In addition, we recorded a $52 million accrual, discounted, relating to future commitments to a third party who assumed a portion of our retained capacity relating to other pipeline projects. Both charges are included in loss on Marcellus Shale upstream divestiture in our consolidated statements of operations in accordance with accounting for exit or disposal activities under ASC 420 – Exit or Disposal Cost Obligations.
Other retained Marcellus Shale firm transportation contracts relate to pipeline projects that are not yet commercially available to us. These projects that are not yet available will undergo construction and, as these projects become commercially available to us, we will assess, based upon the facts and circumstances, the recognition of any potential exit cost liabilities. It is likely we will incur additional firm transportation costs associated with this exit activity in the future. See Note 2. Additional Financial Statement Information and Note 17. Commitments and Contingencies.Production from the Marcellus Shale upstream assets represented 204 MMcfe/d of total consolidated sales volumes for the year ended December 31, 2017. See Supplemental Oil and Gas Information (Unaudited), below for discussion of reserves divested.. After the property sale, we retained certain firm transportation commitments to flow Marcellus Shale natural gas production. See Note 10. Marcellus Shale Firm Transportation Commitments.
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Divestiture of 7.5% Interest in Tamar and Dalit Fields The terms of the Israel Natural Gas Framework (Framework) require us to reduce our current ownership interest in the Tamar and Dalit fields from 32.5% to 25% by year-end 2021. On January 29, 2018, we signed a definitive agreement to divest a 7.5% working interest in each of the fields to Tamar Petroleum Ltd. (TASE: TMRP) (Tamar Petroleum) for cash proceeds of approximately $560 million and 38.5 million shares of Tamar Petroleum. Closing of the transaction is expected by the end of first quarter 2018, subject to satisfactory conclusion of Tamar Petroleum's debt financing and customary approvals, terms and conditions. As of December 31, 2017, the net book value of the 7.5% interest, $293 million, was included in assets held for sale.
Divestiture of Southwest Royalties In January 2018, we signed an agreement to sell our interest in Southwest Royalties, Inc. (Southwest Royalties), a subsidiary of Clayton Williams Energy, and acquired as part of Clayton Williams Energy Acquisition. We received proceeds of $60 million on sale of these assets. As of December 31, 2017, the asset value of these properties of $102 million and associated asset retirement obligation of $42 million were included in assets and liabilities held for sale.
Other US Onshore Transactions We conducted the following additional transactions in 2017:
US Onshore Divestitures During 2017, we received total proceeds of $671 million resulting from the sale of certain US onshore properties, including $568 million related to divestment of non-core acreage in the DJ Basin. Proceeds were applied to reduce field basis with no recognition of gain or loss. A subsequent closing for certain non-core DJ Basin operated properties, in the amount of approximately $40 million, is expected to occur in mid-2018.
Sale of Mineral and Royalty Assets We received $335 million and recognized a gain of $334 million on the sale of mineral and royalty assets covering approximately 140,000 net mineral acres concentrated primarily in Texas, Oklahoma and North Dakota.
Delaware Basin Acquisition In January 2017, we completed the acquisition of Delaware Basin properties, including seven producing wells, thus increasing our contiguous acreage position in the Reeves County area. Consideration totaled $301 million, approximately $246 million of which was allocated to undeveloped leasehold cost. Initial consideration of $30 million was paid into an escrow account in fourth quarter 2016 and reflected as a restricted asset in our consolidated balance sheet as of December 31, 2016.
Marcellus Shale CONE Gathering Divestiture In December 2017, we signed an agreement to sell our 50% interest in CONE Gathering LLC (CONE Gathering) to CNX Resources Corporation. CONE Gathering owns the general partner of CONE Midstream Partners LP (CONE Midstream), which constructs, owns and operates natural gas gathering and other midstream energy assets in the Marcellus Shale. At December 31, 2017, our total investment of $181 million in the CONE entities was included in assets held for sale. We closed the sale in January 2018, receiving proceeds of $308 million in cash and utilized proceeds to pay down borrowings under the Revolving Credit Facility. We now hold 21.7 million common units representing a 33.5% limited partner interests in CNX Midstream Partners LP (NYSE: CNXM). As of December 31, 2017, the net book value of the limited partner interests was approximately $70 million.
Noble Midstream Partners Asset Contribution On June 26, 2017, Noble Midstream Partners acquired an additional 15% limited partner interest in Blanco River DevCo LP (Blanco River DevCo), increasing its ownership to 40% of the Blanco River DevCo LP, and acquired the remaining 20% limited partner interest in Colorado River DevCo LP (Colorado River DevCo) from us for $270 million.
Blanco River DevCo holds Noble Midstream Partners’ Delaware Basin in-field gathering dedications for crude oil and produced water gathering services on approximately 111,000 net acres, with substantially all of the acreage also dedicated for natural gas gathering. Colorado River DevCo provides services across our development areas in the DJ Basin, including crude oil and natural gas gathering and water services in the Wells Ranch area and crude oil gathering in the East Pony area.
The $270 million consideration consisted of $245 million in cash and 562,430 common units representing limited partner interests in Noble Midstream Partners. Noble Midstream Partners funded the cash consideration with approximately $138
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million of net proceeds from a concurrent private placement of common units and $90 million of borrowings under the Noble Midstream Services Revolving Credit Facility (defined below) and the remainder from cash on hand.
Noble Midstream Partners Advantage Joint Venture On April 3, 2017, Noble Midstream Partners and Plains Pipeline, L.P., a wholly owned subsidiary of Plains All American Pipeline, L.P., acquired Advantage Pipeline, L.L.C. (Advantage Pipeline) for $133 million through a newly formed 50/50 joint venture (Advantage Joint Venture). Noble Midstream Partners contributed approximately $67 million of cash to the Advantage Joint Venture, funded by available cash on hand and the Noble Midstream Services Revolving Credit Facility. The Advantage Joint Venture is accounted for under the equity method and is included within our Midstream segment. See Note 7.15. Equity Method Investments.
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| Notes to Consolidated Financial Statements | |
Noble Midstream Partners serves as operator of the Advantage Pipeline System, which includes a 70-mile crude oil pipeline in the Delaware Basin from Reeves County, Texas to Crane County, Texas with 150 MBbls per day of shipping capacity and 490 MBbls of storage capacity.
Noble Midstream Partners Black Diamond Gathering In DecemberOther Acquisitions and Divestitures During 2017, Noble Midstream Partners and Greenfield Midstream, LLC, a portfolio company of EnCap Flatrock Midstream Gathering, formed an entity, Black Diamond Gathering, LLC (Black Diamond Gathering). Black Diamond Gathering subsequently entered into definitive agreements to acquire Saddle Butte Rockies Midstream, LLC and affiliates (collectively, Saddle Butte). The Saddle Butte purchasewe closed on January 31, 2018,the acquisition of other smaller US onshore properties for total cash consideration of approximately $638.5$26 million. Noble Midstream Partners funded its shareWe also closed the sale of the purchase price with proceeds from its December 2017 common unit offering, cash on handcertain other smaller US onshore and borrowings under its unsecured revolving credit facility. See Note 10. Long-Term Debt.Noble Midstream partnersinternational properties and received a 54.4% ownership interest in Black Diamond. Noble Midstream Partners fully consolidates the assets and liabilities of Black Diamond Gathering.
Noble Midstream Partners will serve as operator of Saddle Butte assets which include a large-scale integrated crude oil gathering system in the DJ Basin, consisting of approximately 160 miles of pipeline in operation, 300 MBbls per day of delivery capacity and approximately 210 MBbls of crude oil storage capacity. Saddle Butte has approximately 141,000 dedicated acres from six customers under fixed fee arrangements.
Subsequent Event - Gulf of Mexico DivestitureOn February 15, 2018, we announced the Company signed a definitive agreement to sell its assets in the Gulf of Mexico fortotal cash consideration of $480$39 million, recording a loss of $6 million. As part of the transaction, the buyer will assume all abandonment obligations associated with the properties which we estimate to approximate $230 million as of December 31, 2017. The net book value of the Gulf of Mexico assets as of December 31, 2017 was approximately $750 million. We expect to incur a charge in early 2018, subject to customary closing adjustments. The transaction is expected to close during second quarter 2018, contingent upon the buyer’s successful implementation of its contemplated restructuring, and will be effective as of January 1, 2018.
Year Ended December 31, 2016
Termination of Marcellus Shale JDA In fourth quarter 2016, we and CONSOL Energy Inc. (CONSOL) agreed to terminate our 50-50 Joint Development Agreement (JDA) in the Marcellus Shale. In connection with the terminated JDA, we executed and closed an exchange agreement whereby we and CONSOL each transferred all of our interest in a portion of co-owned properties to one another. In addition to the acreage and production realignment between the two companies, we remitted a cash payment of approximately $213 million to CONSOL at closing. Terminating the JDA resulted in the elimination of the remaining outstanding carried cost obligation due from us. No gain or loss was recognized on the exchange.
DJ Basin Acreage Exchange We closed a cashless acreage exchange in the DJ Basin receiving approximately 11,700 net acres within our Wells Ranch development area in exchange for approximately 13,500 net acres primarily from our Bronco area. No gain or loss was recognized.
2016 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
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
received proceeds of $131 million related to the farm-out of a 35% interest in Block 12, which includes the Aphrodite natural gas discovery, offshore Cyprus. We received the remaining proceeds of $40 million in January 2017. Proceeds were applied to reduce field basis with no recognition of gain or loss.
Year Ended December 31, 2015
2015Other DivestituresIn 2015,During 2016, we soldalso closed the sale of certain non-strategicsmaller US onshore properties receiving proceedsand received total cash consideration of $151$83 million, with no recognition of gain or loss recorded.loss.
Rosetta MergerOn July 20, 2015, Noble Energy completed the Rosetta Merger. The merger was effected through the issuance of approximately 41 million shares of Noble Energy common stock in exchange for all outstanding shares of Rosetta using a ratio of 0.542 of a share of Noble Energy common stock for each share of Rosetta common stock and the assumption of Rosetta's liabilities, including approximately $2 billion fair value of outstanding debt.
The merger added two new US onshore shale positions to our portfolio including approximately 50,000 net acres in the Eagle Ford Shale and 54,000 net acres in the Delaware Basin (45,000 acres in the Delaware Basin and 9,000 acres in the Midland Basin). In connection with the Rosetta Merger, we incurred merger-related costs of approximately $81 million, including (i) $66 million of severance, consulting, investment, advisory, legal and other merger-related fees, and (ii) $15 million of noncash share-based compensation expense, all of which were expensed and are included in other operating (income) expense, net.
Purchase Price Allocation The merger was accounted for as a business combination, using the acquisition method. The allocation of the total purchase price of Rosetta to the assets acquired and the liabilities assumed was based on the fair values at the merger date, with the excess of the purchase price over the fair values of the identifiable net assets acquired recorded as goodwill.
Results of Operations The results of operations attributable to Rosetta are included in our consolidated statements of operations beginning on July 21, 2015. Revenues of $457 million and pre-tax net loss of $20 million, exclusive of a $25 million purchase price allocation adjustment, from Rosetta were generated for the year ended December 31, 2016. Revenues of $181 million and pre-tax net loss of $120 million, inclusive of a $163 million goodwill impairment, from Rosetta were generated from July 21, 2015 to December 31, 2015.
Note 5. Asset Impairments6. Goodwill Impairment
Pre-tax (non-cash) asset impairment charges were as follows:As of December 31, 2017 and through September 30, 2018, our consolidated balance sheet included goodwill of $1.4 billion, of which $1.3 billion, resulting from the Clayton Williams Energy Acquisition, was allocated to our Texas reporting unit, included
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| | | | | | | | | | | |
| | Year Ended December 31, |
| (millions) | 2017 | | 2016 | | 2015 |
| Gulf of Mexico | $ | 63 |
| | $ | — |
| | $ | 158 |
|
| Israel | — |
| | 88 |
| | 36 |
|
| Equatorial Guinea | — |
| | — |
| | 339 |
|
| Other International | 7 |
| | 4 |
| | — |
|
| Total | $ | 70 |
| | $ | 92 |
| | $ | 533 |
|
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
2017 Asset Impairments During 2017, we recorded a non-cash property impairment charge related
within our oil and gas exploration and production segment, and $110 million was allocated to our decisionMidstream 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 pursuefacts 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 Troubadour natural gas discovery in the Gulf of Mexico.
2016 Asset Impairments While the Leviathan natural gas development project, offshore Israel, was not formally sanctioned at December 31, 2016, in fourth quarter 2016, we selected the initial development concept for the first phase of development and wrote off $88 million associated with certain development concepts that were not selected.
2015 Asset ImpairmentsDuring 2015, certain properties were written down to their estimated fair valuesgoodwill using a discounted cash flow model. The cash flow model included management’s estimatesvariety 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, or contract prices as of the date of the estimate, operating and development costs and discount rates. Impairment charges of $481 million resulted from reductions inother factors. The analysis indicated that the forward crude oil prices as of December 31, 2015.
We also recorded impairment charges of approximately $47 million primarily related to revisions in expected field abandonment and other costs for properties in the Gulf of Mexico and offshore Israel and $5 million related to the pending saleimplied fair value of our interest in the Alon ATexas reporting unit goodwill was zero and Alon C licenses, offshore Israel, which included the Karish and Tanin fields.
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| Notes to Consolidated Financial Statements | |
Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs
Capitalized Exploratory Well Costs We capitalize exploratory well costs until a determination is made that the well has found proved reserves or is deemed noncommercial. If a well is deemed to be noncommercial, the well costs are immediately charged to exploration expense as dry hole cost. In addition, wells costs associated with a discovery may be charged to impairment expense if we choose not to pursue development activities.
Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the same period: |
| | | | | | | | | | | |
| | Year Ended December 31, |
| (millions) | 2017 | | 2016 | | 2015 |
| Capitalized Exploratory Well Costs, Beginning of Period | $ | 768 |
| | $ | 1,353 |
| | $ | 1,337 |
|
| Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves | 20 |
| | 84 |
| | 123 |
|
Divestitures and Other (1) | — |
| | (143 | ) | | — |
|
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves or to Assets Held for Sale (2) | (203 | ) | | (1 | ) | | (19 | ) |
Capitalized Exploratory Well Costs Charged to Expense (3) | (65 | ) | | (525 | ) | | (88 | ) |
| Capitalized Exploratory Well Costs, End of Period | $ | 520 |
| | $ | 768 |
| | $ | 1,353 |
|
(1) The 2016 amount relates to the farm-down of a 35% interest in Block 12 offshore Cyprus to a new partner.
(2) The 2017 amount relates to the approval and sanction of the first phase of development of the Leviathan field, offshore Israel.
The 2015 amount relates primarily to US onshore exploration activity.
(3) Capitalized exploratory well costs charged to expense are included within exploration or impairment expense in our consolidated statements of operations.
The 2017 amount relates primarily to the write-off of costs associated with the Troubadour natural gas discovery, Gulf of Mexico, for which we chose not to pursue development activities. SeeNote 5. Asset Impairments.The 2016 amount relates primarily to discoveries offshore West Africa. Following review of additional 3D seismic data, we determined these discoveries were impaired in the current forward outlook for crude oil prices. We also incurred expenses associated with the Silvergate exploratory well in the Gulf of Mexico. The well did not encounter commercial hydrocarbons and was plugged and abandoned.
The 2015 amount relates primarily to a property in northeast Nevada. After assessing its commercial viability in the current commodity price environment, we elected to discontinue exploration efforts.
The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced, and the number of projects that have been capitalized for a period greater than one year: |
| | | | | | | | | | | |
| | December 31, |
| (millions) | 2017 | | 2016 | | 2015 |
| Exploratory Well Costs Capitalized for a Period of One Year or Less | $ | 10 |
| | $ | 69 |
| | $ | 95 |
|
| Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 510 |
| | 699 |
| | 1,258 |
|
| Balance at End of Period | $ | 520 |
| | $ | 768 |
| | $ | 1,353 |
|
| Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 8 |
| | 10 |
| | 14 |
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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, 2017: |
| | | | | | | | | | | | | | | | | |
| | | | Suspended Since | | |
Country/Project (millions) | Total | | 2015 - 2016 | | 2013 - 2014 | | 2012 & Prior | | Progress |
| Gulf of Mexico | | | | | | | | | |
| Katmai | $ | 147 |
| | $ | 56 |
| | $ | 91 |
| | $ | — |
| | Progressing a development scenario for this 2014 crude oil discovery. We are currently conducting feasibility and front-end engineering and design studies on host platform options. |
| Offshore Equatorial Guinea | | | | | | | | | |
| Felicita (Block O) | 47 |
| | 3 |
| | 12 |
| | 32 |
| | Evaluating regional development scenarios for this 2008 gas discovery. During 2014, we conducted additional seismic activity over Blocks I and O and in early 2016, we began analyzing, interpreting and evaluating the acquired seismic data. |
| Yolanda (Block I) | 23 |
| | 1 |
| | 6 |
| | 16 |
| | A data exchange agreement for the 2007 Yolanda condensate and natural gas discovery has been executed between the governments of Equatorial Guinea and Cameroon. Our natural gas development team is working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options for both Yolanda and YoYo (Cameroon) discoveries. |
| Offshore Cameroon | |
| | |
| | |
| | |
| | |
| YoYo (YoYo Block) | 55 |
| | 4 |
| | 6 |
| | 45 |
| | A data exchange agreement for the 2007 YoYo condensate and natural gas discovery has been executed between the governments of Equatorial Guinea and Cameroon. Our natural gas development team is working with both governments to evaluate natural gas monetization options for both Yolanda (Equatorial Guinea) and YoYo discoveries. In June 2017, we converted our mining concession license for the YoYo block into a PSC. |
| Offshore Israel | |
| | |
| | |
| | |
| | |
| Leviathan-1 Deep | 91 |
| | 8 |
| | 10 |
| | 73 |
| | The well did not reach the target interval in 2012. We continue to reprocess and review seismic information for this discovery, based on information obtained from other recent discoveries in the region, and develop future drilling plans to test this deep oil concept, which is held by the Leviathan Development and Production Leases. |
| Dalit | 32 |
| | 3 |
| | 5 |
| | 24 |
| | Our future development plan was approved by the Government of Israel to develop this 2009 natural gas discovery with a tie-in to existing infrastructure at Tamar. See also Note 4. Acquisitions, Divestitures and Merger. |
| Offshore Cyprus | | | | | | | | | |
| Cyprus | 97 |
| | 15 |
| | 52 |
| | 30 |
| | In 2016, we farmed-down a 35% interest in Block 12 and submitted an updated development plan. We continue to work with the Government of Cyprus to obtain approval of the development plan and the subsequent issuance of an Exploitation License. Receiving an Exploitation License will allow us and our partners to perform the necessary engineering and design studies and progress the project to final investment decision. During 2017, we submitted an updated development plan, progressed capital project cost improvement and continued regional natural gas marketing efforts. |
| Other | |
| | |
| | |
| | |
| | |
| Projects less than $20 million | 18 |
| | (9 | ) | | 21 |
| | 6 |
| | Continuing to assess and evaluate wells. |
| Total | $ | 510 |
| | $ | 81 |
| | $ | 203 |
| | $ | 226 |
| | |
Undeveloped Leasehold Costs We reclassify undeveloped leasehold costs to proved property costs when proved reserves, including PUDs, become attributable to the property as a result of our exploration and development activities. On the other
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
hand, if, based upon a change in exploration plans, timing and extent of development activities, availability of capital and suitable rig and drilling equipment, resource potential, comparative economics, changing regulations and/or other factors, an impairment is indicated, we record impairment expense related to the respective leases or licenses.
As of December 31, 2017, we had remaining undeveloped leasehold costs, to which proved reserves had not been attributed, of$2.8 billion, including $1.6 billion related to Delaware Basin assets acquired in the Clayton Williams Energy Acquisition in 2017, and $1.1 billion and $149 million attributable to Delaware Basin and Eagle Ford Shale assets, respectively, acquired in the Rosetta Merger in 2015. Undeveloped leasehold costs were derived from allocated fair values as a result of business combinations or other purchases of unproved properties and are subject to impairment testing.
The remaining balance of undeveloped leasehold costs as of December 31, 2017 included $44 million related to Gulf of Mexico unproved properties and $53 million related to international unproved properties. These costs pertain to acquired leases or licenses that are subject to expiration over the next several years unless production is established on units containing the acreage. These costs are evaluated as part of our periodic impairment review.
During 2017, we completed geological evaluations of certain Gulf of Mexico leases and licenses and leases and licenses associated with other international unproved properties. We determined that several leases and licenses should be relinquished or exited. As a result, we recognized undeveloped leasehold impairment expensea loss of $62 million primarily attributable to Gulf of Mexico leases. We recorded leasehold impairment expense of $93 million in 2016 and $21 million in 2015. This expense is included in exploration expense in the consolidated statements of operations.$1.3 billion.
Note 7. Equity Method InvestmentsCapitalized Exploratory Well Costs and Undeveloped Leasehold Costs
Equity Method Investments Investments accounted for underCapitalized Exploratory Well Costs We capitalize exploratory well costs until a determination is made that the equity method consist primarilywell has found proved reserves or is deemed noncommercial. On a quarterly basis, we review the status of suspended exploratory well costs and assess the following:development of these projects. If a well is deemed to be noncommercial, the well costs are charged to exploration expense as dry hole cost.
34% interestChanges in CONE Midstream, a public master limited partnership, which constructs, ownscapitalized exploratory well costs, excluding amounts that were capitalized and operates natural gas gathering and other midstream energy assetssubsequently expensed in the Marcellus Shale;
45% interest in Atlantic Methanol Production Company, LLC (AMPCO), which owns and operates a methanol plant and related facilities in Equatorial Guinea; and
28% interest in Alba Plant LLC (Alba Plant), which owns and operates a liquefied petroleum gas (LPG) processing plant in Equatorial Guinea.
CONE Midstream Dropdown Transaction In fourth quarter 2016, CONE Midstream completed an acquisition of midstream assets (dropdown) from CONE Gathering. CONE Gathering subsequently distributed $70 million cash and additional CONE Midstream common units to us.
Equity method investmentssame period, are as follows: |
| | | | | | | | | | | |
| | Year Ended December 31, |
| (millions) | 2018 | | 2017 | | 2016 |
| Capitalized Exploratory Well Costs, Beginning of Period | $ | 520 |
| | $ | 768 |
| | $ | 1,353 |
|
| Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves | 7 |
| | 20 |
| | 84 |
|
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 |
|
|
| | | | | | | | |
| | | December 31, |
| (millions) | | 2017 | | 2016 |
| Equity Method Investments | | | | |
CONE Investments(1) | | $ | — |
| | $ | 172 |
|
| AMPCO | | 129 |
| | 120 |
|
| Alba Plant | | 80 |
| | 82 |
|
| Advantage Pipeline | | 70 |
| | — |
|
| Other | | 26 |
| | 26 |
|
| Total Equity Method Investments | | $ | 305 |
| | $ | 400 |
|
| |
(1)
| CONE Investments include CONE Midstream and CONE Gathering. The investments are included in assets held for sale at December 31, 2017. |
Other At December 31, 2017, consolidated retained earnings included $90 million(1) The 2018 amount represents costs primarily related to Gulf of Mexico assets sold during second quarter and the undistributed earnings2016 amount relates to the farm-down of equity method investees.a 35% interest in Block 12 offshore Cyprus to a new partner.
(2)The carrying value of our AMPCO investment was $12 million higher than2017 amount relates to the underlying net assetsapproval and sanction of the investee at December 31, 2017. The difference is related to capitalized interest which is being amortized into earnings over the remaining useful lifefirst phase of development of the plant.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: |
| | | | | | | | | | | |
| | December 31, |
| (millions) | 2018 | | 2017 | | 2016 |
| Exploratory Well Costs Capitalized for a Period of One Year or Less | $ | 6 |
| | $ | 10 |
| | $ | 69 |
|
| Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 348 |
| | 510 |
| | 699 |
|
| Balance at End of Period | $ | 354 |
| | $ | 520 |
| | $ | 768 |
|
| 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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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Summarized, 100% combined financial informationThe following table provides a further aging of those exploratory well costs that have been capitalized for equity method investees isa period greater than one year since the commencement of drilling as follows:of December 31, 2018: |
| | | | | | | | | | | | | | | | | |
| | | | 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 |
| | |
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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| | | December 31, |
| (millions) | | 2017 | | 2016 |
| Balance Sheet Information | | | | |
| Current Assets | | $ | 390 |
| | $ | 313 |
|
| Noncurrent Assets | | 588 |
| | 1,390 |
|
| Current Liabilities | | 171 |
| | 149 |
|
| Noncurrent Liabilities | | 90 |
| | 256 |
|
|
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| (millions) | | 2017 | | 2016 | | 2015 |
| Statements of Operations Information | | | | | | |
| Operating Revenues | | $ | 790 |
| | $ | 667 |
| | $ | 645 |
|
| Operating Expenses | | 303 |
| | 355 |
| | 393 |
|
| Operating Income | | 487 |
| | 312 |
| | 252 |
|
| Other (Income) Net | | (15 | ) | | (7 | ) | | (9 | ) |
| Income Before Income Taxes | | 502 |
| | 319 |
| | 261 |
|
| Income Tax Provision | | 136 |
| | 60 |
| | 46 |
|
| Net Income | | $ | 366 |
| | $ | 259 |
| | $ | 215 |
|
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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. Derivative InstrumentsAsset Retirement Obligations
ARO consists primarily of estimated costs of dismantlement, removal, site reclamation and Hedging Activitiessimilar activities associated with our oil and gas properties. Changes in ARO are as follows: |
| | | | | | | |
| | Year Ended December 31, |
| (millions) | 2018 | | 2017 |
| Asset Retirement Obligations, Beginning Balance | $ | 875 |
| | $ | 935 |
|
| Liabilities Incurred | 25 |
| | 94 |
|
| Liabilities Settled | (345 | ) | | (82 | ) |
| Revisions of Estimates | 293 |
| | (65 | ) |
| Reclassification to Liabilities Associated with Assets Held for Sale | (1 | ) | | (54 | ) |
| Accretion Expense | 33 |
| | 47 |
|
| Asset Retirement Obligations, Ending Balance | $ | 880 |
| | $ | 875 |
|
ObjectiveYear Ended December 31, 2018 Liabilities settled primarily included $216 million and Strategies$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.
Revisions of estimates were primarily related to increases in cost estimates and changes in timing estimates of $287 million for Using Derivative InstrumentsUS 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. Long-Term Debt
Our debt consists of the following: |
| | | | | | | | | | | | | |
| | December 31, 2018 | | December 31, 2017 |
| (millions, except percentages) | Debt | | Interest Rate | | Debt | | Interest Rate |
| 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 | % |
| Senior Notes, due December 15, 2021 | 1,000 |
| | 4.15 | % | | 1,000 |
| | 4.15 | % |
| Senior Notes, due October 15, 2023 | 100 |
| | 7.25 | % | | 100 |
| | 7.25 | % |
| Senior Notes, due November 15, 2024 | 650 |
| | 3.90 | % | | 650 |
| | 3.90 | % |
| Senior Notes, due April 1, 2027 | 250 |
| | 8.00 | % | | 250 |
| | 8.00 | % |
| Senior Notes, due January 15, 2028 | 600 |
| | 3.85 | % | | 600 |
| | 3.85 | % |
| Senior Notes, due March 1, 2041 | 850 |
| | 6.00 | % | | 850 |
| | 6.00 | % |
| Senior Notes, due November 15, 2043 | 1,000 |
| | 5.25 | % | | 1,000 |
| | 5.25 | % |
| Senior Notes, due November 15, 2044 | 850 |
| | 5.05 | % | | 850 |
| | 5.05 | % |
| Senior Notes, due August 15, 2047 | 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 |
| | |
|
| Less Amounts Due Within One Year: | |
| | |
| | |
| | |
|
| Capital Lease Obligations | (41 | ) | | |
| | (61 | ) | | |
|
| Long-Term Debt Due After One Year | $ | 6,574 |
| | |
| | $ | 6,746 |
| | |
|
| |
(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 FacilityOur 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.
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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 in the Revolving Credit Facility), expressed as a percentage, not exceed 65% at any time. A violation of this covenant could result in a default under the Credit Agreement, which would permit the participating banks to restrict our ability to access the Revolving Credit Facility and require the immediate repayment of any outstanding advances under the Revolving Credit Facility. 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 date of the Revolving Credit Facility from August 2020 to March 2023. As of December 31, 2018, no borrowings were outstanding under the Revolving Credit Facility.
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 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.
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 Noble Midstream Services 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, Noble Midstream Services entered into a Term Credit Agreement (Noble Midstream Services Term Credit Agreement), which provides for a three year senior unsecured term loan credit facility (Noble Midstream Services Term Loan Credit Facility) and permits aggregate borrowings of up to $500 million. Proceeds from the Noble Midstream Services Term Loan Credit Facility were 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 the Noble Midstream Services Term Loan Credit Facility.
Borrowings under the Noble Midstream Services Term Loan Credit Facility bear interest at 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. As of December 31, 2018, $500 million was outstanding 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 Loan Credit Facility, the lenders may declare all amounts outstanding under the Noble Midstream Services Term Loan Credit Facility to be immediately due and payable and exercise other remedies as provided by applicable law.
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 On August 15, 2017, we issued $600 million of 3.85% senior unsecured notes that will mature on January 15, 2028 and $500 million of 4.95% senior unsecured notes that will mature on August 15, 2047. Interest on the 3.85% senior notes and 4.95% senior notes is payable semi-annually beginning January 15, 2018 and
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
February 15, 2018, respectively. We may enter into crude oilredeem 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 natural gas price hedging arrangements in an effortdebt 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 mitigatefund the effectstender offer and the redemption of commodity price volatility and enhance the predictability$1.1 billion of cash flows relatingour 8.25% senior notes due March 1, 2019. As a result, we paid a premium of $96 million to the marketingholders 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 crude oil and natural gas production. The derivative instruments we use may include variable to fixed price commodity swaps, enhanced swaps, two-way and three-way collars, basis swaps and/or put options.
The fixed price swap and two-way collar contracts entitle us (floating price payor) to receive settlement from the counterparty (fixed price payor) for each calculation period in amounts, if any, by which the settlement priceshare of costs 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 productinitial phase of development of the notional quantity per calculation period andLeviathan field. No amounts were ever drawn on the excessfacility, which was terminated in December 2018.
Fair Value of the floating price over the fixed or ceiling price in respect of each calculation period. The amount payable by the counterparty, if the floating price is below the fixed or floor price, is the product of the notional quantity per calculation period and the excess of the fixed or floor price over the floating price in respect of each calculation period.
A three-way collar consists of a two-way collar contract combined with a put option contract sold by us with a strike price below the floor price of the two-way collar. We receive price protection at the purchased put option floor price of the two-way collar if commodity prices are above the sold put option strike price. If commodity prices fall below the sold put option strike price, we receive the cash market price plus the delta between the two put option strike prices. This type of instrument allows us to capture more value in a rising commodity price environment, but limits our benefits in a downward commodity price environment.
For put options, we typically pay a premium to the counterparty in exchange for the sale of the instrument. If the index price is below the floor price of the put option, we receive the difference between the floor price and the index price multiplied by the contract volumes less the option premium at the time of settlement. If the index price settles at or above the floor price of the put option, we pay only the put option premium at the time of settlement. We had no outstanding put options as of December 31, 2017.
While these instruments mitigate the cash flow risk of future reductions in commodity prices, they may also curtail benefits during periods of increasing commodity prices.
Debt See Note 13.14. 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 derivative instruments.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 contractual 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 contractual 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 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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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Counterparty Credit RiskDerivative instruments expose usAdditional retained contracts relate to counterparty credit risk. Ourthe 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 derivative instruments are currently with a diversified group of major banks or market participants, andbefore it is transferred to the customer.
In addition to the retained firm transportation commitments, we monitor and manage our level of financial exposure. Our commodity derivative contracts are executed under master agreements which allow us, inalso have the event of default, to elect early termination of all contractsfollowing accrued discounted liabilities associated with the defaulting counterparty. Ifexit 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 choose to elect early termination, all assetentered into capacity release agreements with third parties extending through March and liability positionsOctober 2020, respectively. Revenues and expenses associated with the defaulting counterparty would be net settled at the time of election.
We monitor the creditworthiness of our commodity derivatives counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our abilitythese agreements, as well as those associated with purchasing and selling third-party natural gas to mitigate an increase in counterparty credit risk.
Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices and could incur a loss.
Unsettled Derivative Instruments As of December 31, 2017, we had entered into the following crude oil derivative instruments:
Leach/Rayne Xpress capacity, are as follows: |
| | | | | | | | | | | | | | | | | |
| | | | | | Swaps | | Collars |
Settlement Period | Type of Contract | Index | Bbls Per Day | | Weighted Average Fixed Price | | Weighted Average Short Put Price | Weighted Average Floor Price | Weighted Average Ceiling Price |
| 2018 | Three-Way Collars | NYMEX WTI | 10,000 | | $ | — |
| | $ | 45.50 |
| $ | 52.50 |
| $ | 69.09 |
|
| 2018 | Swaps | NYMEX WTI | 24,000 | | 57.09 |
| | — |
| — |
| — |
|
| 2018 | Two-Way Collars | NYMEX WTI | 18,000 | | — |
| | — |
| 50.42 |
| 58.82 |
|
| 2018 | Three-Way Collars | Dated Brent | 3,000 | | — |
| | 40.00 |
| 50.00 |
| 70.41 |
|
| 2018 | Swaps | ICE Brent | 2,000 | | 59.00 |
| | — |
| — |
| — |
|
| 2018 | Two-Way Collars | ICE Brent | 2,000 | | — |
| | — |
| 50.00 |
| 55.25 |
|
| 2018 | Three-Way Collars | ICE Brent | 5,000 | | — |
| | 43.00 |
| 50.00 |
| 59.50 |
|
| 2018 | Basis Swaps | (1) | 12,000 | | (0.60 | ) | | — |
| — |
| — |
|
| 2019 | Swaps | NYMEX WTI | 3,000 | | 55.07 |
| | — |
| — |
| — |
|
| 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) | 12,000 | | (1.01 | ) | | — |
| — |
| — |
|
|
| | | | | | | | | | | | | | |
| | | | | 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) | We have entered into crude oil basis swap contractsIncludes the net impact of the difference in orderthe firm transportation contract rates and the rates agreed to fixin the differential between pricing in Midland, Texas, and Cushing, Oklahoma. The weighted average differential represents thecapacity releases. Additionally, amount includes transportation expense associated with our transport of reduction to Cushing, Oklahoma, prices for the notional volumes covered by the basis swap contracts.purchased natural gas on Leach/Rayne Xpress. |
AsWe expect to continue our commercialization actions, including utilizing pipeline capacity through purchases of December 31, 2017, we had entered into the followingthird-party natural gas derivative instruments:
|
| | | | | | | | | | | | | |
| | | | | Collars |
Settlement Period | Type of Contract | Index | MMBtu Per Day | Weighted Average Short Put Price | Weighted Average Floor Price | Weighted Average Ceiling Price |
| 2018 | Three-Way Collars | NYMEX HH | 120,000 |
| $ | 2.50 |
| $ | 2.88 |
| $ | 3.65 |
|
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Fair Value Amounts and Gains and Losses on Derivative InstrumentsThe fair values of derivative instruments in our consolidated balance sheets were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | |
Fair Value of Derivative Instruments (1) |
| | Asset Derivative Instruments | | Liability Derivative Instruments |
| | December 31,
2017 | | December 31,
2016 | | December 31,
2017 | | December 31,
2016 |
| | Balance Sheet Location | | Fair Value | | Balance Sheet Location | | Fair Value | | Balance Sheet Location | | Fair Value | | Balance Sheet Location | | Fair Value |
| (millions) | | | | | | | | | | | | | | | |
Commodity Derivative Instruments | Current Assets | | $ | 2 |
| | Current Assets | | $ | — |
| | Current Liabilities | | $ | 58 |
| | Current Liabilities | | $ | 102 |
|
| | Noncurrent Assets | | — |
| | Noncurrent Assets | | — |
| | Noncurrent Liabilities | | 15 |
| | Noncurrent Liabilities | | 14 |
|
| Total | | | $ | 2 |
| | | | $ | — |
| | | | $ | 73 |
| | | | $ | 116 |
|
(1) See Note 1. Summary of Significant Accounting Policies – Derivative Instruments and Hedging Activities for a discussionsales to other third parties, to mitigate these firm transportation commitments. Some of our netting policy.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 Divestitures.
Subsequent Event In January 2019, we executed agreements on Leach/Rayne Xpress to permanently assign the remaining capacity to a third-party effective January 1, 2021 extending through the remainder of the contract term. The effectpermanent assignment reduces our total undiscounted financial commitment under the Marcellus Shale firm transportation contracts by approximately $350 million. In January 2019, we recorded exit costs of derivative instruments on our consolidated statements$92 million, discounted, related to future commitments to the third-party. We will continue efforts to mitigate the impact of operations was as follows:these transportation agreements during 2019 and 2020.
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| (millions) | 2017 | | 2016 | | 2015 |
| Cash (Received) Paid in Settlement of Commodity Derivative Instruments | | | | | |
| Crude Oil | $ | (14 | ) | | $ | (499 | ) | | $ | (844 | ) |
| Natural Gas | 1 |
| | (70 | ) | | (147 | ) |
NGLs (1) | — |
| | — |
| | (18 | ) |
| Total Cash Received in Settlement of Commodity Derivative Instruments | (13 | ) | | (569 | ) | | (1,009 | ) |
| Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments | | | | | |
| Crude Oil | 18 |
| | 582 |
| | 423 |
|
| Natural Gas | (68 | ) | | 126 |
| | 65 |
|
NGLs (1) | — |
| | — |
| | 20 |
|
| Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments | (50 | ) | | 708 |
| | 508 |
|
| (Gain) Loss on Commodity Derivative Instruments | | | | | |
| Crude Oil | 4 |
| | 83 |
| | (421 | ) |
| Natural Gas | (67 | ) | | 56 |
| | (82 | ) |
NGLs (1) | — |
| | — |
| | 2 |
|
| Total (Gain) Loss on Commodity Derivative Instruments | $ | (63 | ) | | $ | 139 |
| | $ | (501 | ) |
| |
(1)
| Amounts for NGLs relate to commodity derivative instruments, acquired in the Rosetta Merger, which expired as of December 31, 2015. |
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Note 9. Asset Retirement Obligations11. Commitments and Contingencies
Asset retirement obligations (AROs) consist primarilyLegal Proceedings We are involved in various legal proceedings in the ordinary course of estimated costsbusiness. 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 dismantlement, removal, site reclamationsuch 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 similar activities associated withState 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 properties. Changes in AROs were as follows: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. |
| | | | | | | |
| | Year Ended December 31, |
| (millions) | 2017 | | 2016 |
| Asset Retirement Obligations, Beginning Balance | $ | 935 |
| | $ | 989 |
|
| Liabilities Incurred | 94 |
| | 21 |
|
| Liabilities Settled | (82 | ) | | (120 | ) |
| Revision of Estimate | (65 | ) | | (3 | ) |
| Reclassification to Liabilities Associated with Assets Held for Sale | (54 | ) | | — |
|
| Accretion Expense | 47 |
| | 48 |
|
| Asset Retirement Obligations, Ending Balance | $ | 875 |
| | $ | 935 |
|
Year Ended December 31, 2017 Liabilities incurred include $63 million related to the Clayton Williams Energy Acquisition and $31 million primarily for other US onshore wells and midstream facilities placed into service.
Liabilities settled include $43 million related to abandonment of US onshore properties, $19 million related to properties sold in the Greeley Crescent (DJ Basin) acreage divestiture, $12 million related to properties sold in the Marcellus Shale upstream divestiture and $8 million related to other offshore domestic and international properties.
Revisions of estimates include a $42 million decrease related to changes in cost and timing associated with the North Sea abandonment project and a $38 million decrease for US onshore and Gulf of Mexico properties, partially offset by an increase of $15 million for West Africa.
Year Ended December 31, 2016 Liabilities incurred were due to new wells and facilities placed into service for US onshore, Gulf of Mexico, and offshore Israel.
Liabilities settled were related to wells and facilities permanently abandoned at the end of their useful lives and to assets sold. Settlements included $65 million related to abandonment of Gulf of Mexico properties, $49 million related to US onshore properties abandoned or sold, $5 million related to offshore Israel properties and $1 million related to the North Sea.
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Note 10. Long-Term Debt
Our debt consistsThe Consent Decree, which alleges violations of the following: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. 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. |
| | | | | | | | | | | | | |
| | December 31,
2017 | | December 31,
2016 |
| (millions, except percentages) | Debt | | Interest Rate | | Debt | | Interest Rate |
| Revolving Credit Facility, due August 27, 2020 | $ | 230 |
| | 2.27 | % | | $ | — |
| | — | % |
| Noble Midstream Services Revolving Credit Facility, due September 20, 2021 | 85 |
| | 2.49 | % | | — |
| | — | % |
Term Loan Facility, due January 6, 2019 (1) | — |
| | — | % | | 550 |
| | 2.01 | % |
Leviathan Term Loan Facility, due February 23, 2025
| — |
| | — | % | | — |
| | — |
|
Senior Notes, due March 1, 2019 (2) | — |
| | — | % | | 1,000 |
| | 8.25 | % |
| Senior Notes, due May 1, 2021 | 379 |
| | 5.63 | % | | 379 |
| | 5.63 | % |
| Senior Notes, due December 15, 2021 | 1,000 |
| | 4.15 | % | | 1,000 |
| | 4.15 | % |
Senior Notes, due June 1, 2022 (1)
| — |
| | — | % | | 18 |
| | 5.88 | % |
| Senior Notes, due October 15, 2023 | 100 |
| | 7.25 | % | | 100 |
| | 7.25 | % |
Senior Notes, due November 15, 2024
| 650 |
| | 3.90 | % | | 650 |
| | 3.90 | % |
| Senior Notes, due April 1, 2027 | 250 |
| | 8.00 | % | | 250 |
| | 8.00 | % |
Senior Notes, due January 15, 2028 (2)
| 600 |
| | 3.85 | % | | — |
| | — | % |
| Senior Notes, due March 1, 2041 | 850 |
| | 6.00 | % | | 850 |
| | 6.00 | % |
| Senior Notes, due November 15, 2043 | 1,000 |
| | 5.25 | % | | 1,000 |
| | 5.25 | % |
Senior Notes, due November 15, 2044
| 850 |
| | 5.05 | % | | 850 |
| | 5.05 | % |
Senior Notes, due August 15, 2047 (2)
| 500 |
| | 4.95 | % | | — |
| | — | % |
Other Senior Notes and Debentures (3)
| 92 |
| | 7.13 | % | | 92 |
| | 7.13 | % |
Capital Lease and Other Obligations (4)
| 273 |
| | — | % | | 375 |
| | — | % |
| Total | $ | 6,859 |
| | |
| | $ | 7,114 |
| | |
|
| Unamortized Discount | (24 | ) | | |
| | (23 | ) | | |
|
Unamortized Premium (2) | 12 |
| | | | 17 |
| | |
| Unamortized Debt Issuance Costs | (40 | ) | | | | (34 | ) | | |
| Total Debt, Net of Discount | $ | 6,807 |
| | |
| | $ | 7,074 |
| | |
|
| Less Amounts Due Within One Year | |
| | |
| | |
| | |
|
| Capital Lease and Other Obligations | (61 | ) | | |
| | (63 | ) | | |
|
| Long-Term Debt Due After One Year | $ | 6,746 |
| | |
| | $ | 7,011 |
| | |
|
| |
(1)
| In fourth quarter 2017, we repaid $550 million of borrowings under the Term Loan Facility and $18 million of our outstanding Senior Notes due June 1, 2022. |
| |
(2)
| In third quarter 2017, we redeemed all of our Senior Notes due March 1, 2019 and issued Senior Notes due January 15, 2028 and August 15, 2047. |
| |
(3)
| Includes $8 million of Senior Notes due June 1, 2024 and $84 million of Senior Debentures due August 1, 2097. The weighted average interest rate for these instruments is 7.13%. |
| |
(4)
| The reduction from 2016 includes $41 million related to other obligations for drilling commitments assumed by the acquirer of the Marcellus Shale upstream assets and $60 million of capital lease principal payments. |
AllWe 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 long-term debt is senior unsecured debtMarcellus Shale upstream divestiture, we retained certain transportation and is, therefore, pari passu with respectgathering obligations to flow Marcellus Shale natural gas production to various markets inside and outside of the payment of both principalMarcellus Basin. See Note 10. Marcellus Shale Firm Transportation Commitments. Other Transportation 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,Gathering Obligations We have transportation and gathering obligations to flow US onshore production, primarily in the opinion of a nationally recognized accounting firm,DJ Basin, to pay all scheduled principal and interest due under the respective agreements. Interest on eachvarious markets.Certain of these issues is payable semi-annually.contracts require us to make payments for any
Revolving Credit FacilityOur Revolving Credit Facility (i) provides for facility fee rates that range from 10 basis points to 25 basis points per year depending upon our credit rating, (ii) includes sub-facilities for short-term loans and letters of credit up to an aggregate amount of $500 million under each sub-facility and (iii) provides for interest rates that are based upon the Eurodollar rate plus a margin that ranges from 90 basis points to 150 basis points depending upon our credit rating.
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
The Revolving Credit Facility requires that our total debtshortfalls 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 capitalization ratio (as definedmeet 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 Revolving Credit Facility), expressednear-term. These amounts are recorded as a percentage, not exceed 65% at any time. A violation of this covenant could result in a default under the Credit Agreement, which would permit the participating banks to restrict our ability to access the Revolving Credit Facility and require the immediate repayment of any outstanding advances under the Revolving Credit Facility. As of December 31, 2017, we were in compliance with our debt covenants.
The Revolving Credit Facility is available for general corporate purposes. Certain lenders that are a party to the Revolving Credit Facility have in the past performed, and may in the future from time to time perform, investment banking, financial advisory, lending or commercial banking services for us for which they have received, and may in the future receive, customary compensation and reimbursement of expenses.
Noble Midstream Services Revolving Credit Facility On September 20, 2016, Noble Midstream Services LLC (Noble Midstream Services), a subsidiary of Noble Midstream Partners, entered into a credit agreement for a $350 million revolving credit facility (Noble Midstream Services Revolving Credit Facility). The Noble Midstream Services Revolving Credit Facility has a five year maturity and includes a letter of credit sublimit of up to $100 million for issuances of letters of credit. The borrowing capacity on the Noble Midstream Services Revolving Credit Facility may be increased by an additional $350 million, subject to certain conditions, and is available to fund working capital and to finance acquisitions and other capital expenditures of Noble Midstream Partners.
Borrowings by Noble Midstream Services under the Noble Midstream Services Revolving Credit Facility bear interest at a rate equal to an applicable margin plus, at Noble Midstream Service's option, either:
in the case of base rate borrowings, a rate equal to the highest of (1) the prime rate, (2) the greater of the federal funds rate or the overnight bank funding rate, plus 0.5% and (3) the London interbank offered rate (LIBOR) for an interest period of one month plus 1.00%; or
in the case of LIBOR borrowings, the offered rate per annum for deposits of dollars for the applicable interest period.
The Noble Midstream Services Revolving Credit Facility includes certain financial covenants as of the end of each fiscal quarter, including a (1) consolidated leverage ratio to consolidated adjusted earnings before interest expense, income taxes, depreciation, depletion, and amortization (EBITDA) and (2) consolidated interest coverage ratio (each covenant as described in the Noble Midstream Services Revolving Credit Facility). All obligations of Noble Midstream Services, as the borrower under the Noble Midstream Services Revolving Credit Facility, are guaranteed by Noble Midstream Partners and all wholly-owned material subsidiaries of Noble Midstream Partners. Debt issuance costs associated with this facility were de minimis.
On January 31, 2018, in connection with the acquisition of Saddle Butte, Noble Midstream Partners drew an additional $300 million under the Noble Midstream Services Revolving Credit Facility and partially exercised the accordion feature, increasing the commitments under the credit agreement to $530 million.
Senior Notes Issuance and Completed Tender Offer On August 15, 2017, we issued $600 million of 3.85% senior unsecured notes that will mature on January 15, 2028 and $500 million of 4.95% senior unsecured notes that will mature on August 15, 2047. Interest on the 3.85% senior notes and 4.95% senior notes is payable semi-annually beginning January 15, 2018 and February 15, 2018, respectively. We may redeem some or all of the senior notes at any time at the applicable redemption price, plus accrued interest, if any. The senior notes were issued at a discount of $4 million and debt issuance costs incurred totaled $11 million, both of which are reflected as a reduction of long-term debt and are amortized over the life of the notes. Proceeds of $1 billion from the issuance of senior notes were used solely to fund the tender offer and the redemption of $1 billion of our 8.25% senior notes due March 1, 2019. As a result, we paid a premium of $96 million to the holders of the 8.25% senior notes and recognized a loss of $98 million in third quarter 2017, which is reflected in other non-operating (income)marketing expense in our consolidated statements of operations.
Leviathan Term Loan Facility On February 24,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, Noble Energy Mediterranean Ltd. (NEML), a wholly-owned subsidiaryand $76 million in 2016.
Minimum commitments as of Noble Energy, entered into a facility agreement (Leviathan Term Loan Facility) which provides for a limited recourse secured term loan facility with an aggregate principal borrowing amount of up to $1.0 billion, of which $625 million is initially committed. Any amounts borrowed under the Leviathan Term Loan Facility will be available to fund a portion of our share of costs for the initial phase of developmentDecember 31, 2018 consist of the Leviathan field offshore Israel.
Any amounts borrowed will be subject to repayment on a quarterly basis following production startup for the first phase of development, which is targeted for the end of 2019. Repayment will be in accordance with an amortization schedule set forth in the facility agreement, with a final balloon payment of no more than 35% of the loans outstanding. The Leviathan Term Loan Facility matures on February 23, 2025 and we can prepay borrowings at any time, in whole or in part, without penalty. The Leviathan Term Loan Facility contains customary representations and warranties, affirmative and negative covenants, and
following:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| (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 |
|
| |
(1) | Amount includes exit cost obligations resulting from 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 are 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 | ) |
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
events of default and also includes a prepayment mechanism that reduces the final balloon amount if cash flows exceed certain defined coverage ratios.
Any amounts borrowed will accrue interest at LIBOR, plus a margin of 3.50% per annum prior to production startup, 3.25% during the period following production startup until the last two years of maturity, and 3.75% during the last two years until the maturity date. We are also required to pay a commitment fee equal to 1.00% per annum on the unused and available commitments under the Leviathan Term Loan Facility until the beginningThe income tax provision (benefit) consists of the repayment period.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 | % |
The Leviathan Term Loan FacilityA reconciliation of the federal statutory tax rate to the effective tax rate is secured by a first priority security interest in substantially allas 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 NEML's interestsForeign Subsidiaries, below.
|
| | |
| 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 Leviathan field and its marketing subsidiary, and in assets related to the initial phase of the project. All of NEML’s revenues from the first phase of Leviathan development will be deposited in collateral accounts, and we will be required to maintain a debt service reserve account for the benefit of the lenders under the Leviathan Term Loan Facility. Once servicing accounts are replenished and debt service made, all remaining cash will be available to us and our subsidiaries.
Term Loan Facility and Completed Tender Offers On January 6, 2016, we entered into a term loan agreement (Term Loan Facility), which provided for a three-year term loan facility for a principal amount of $1.4 billion. Provisions of the Term Loan Facility were consistent with those in the Revolving Credit Facility. Borrowings under the Term Loan Facility could be prepaid prior to maturity without premium. The Term Loan Facility accrued interest, at our option, at either (a) a base rate equal to the highest of (i) the rate announced by Citibank, N.A., as its prime rate, (ii) the Federal Funds Rate plus 0.5%, and (iii) a LIBOR plus 1.0%, plus a margin that ranged from 10 basis points to 75 basis points depending upon our credit rating, or (b) a LIBOR, plus a margin that ranged from 100 basis points to 175 basis points depending upon our credit rating.
Borrowings under the Term Loan Facility were used solely to fund tender offers for approximately $1.38 billion of notes assumed in the Rosetta Merger in 2015. As a result of the tender offers, we recognized a gain of $80 million in first quarter 2016 which is reflected in other non-operating (income) expense in our consolidated statements of operations. In fourth quarter 2016, we prepaid $850 million of the amount outstanding under the Term Loan Facility from cash on hand. In fourth quarter 2017, we repaid the remaining outstanding balance of $550 million under this facility using proceeds received from the sale of non-core Greeley Crescent and Bronco acreage in the DJ Basin.
Fair Value of Debt See Note 13. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of debt.Capital Lease and Other Obligations The amount of the capital lease obligation is based on the discounted present value of future minimum lease payments, and therefore does not reflect future cash lease payments. Amounts due within one year equal the amount by which the capital lease obligation is expected to be reduced during the next 12 months. See Note 17. Commitments and Contingencies for future capital lease payments.Annual Debt MaturitiesAnnual maturities of outstanding debt, excluding capital lease payments, as of December 31, 2017 aresheets 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 | ) |
|
| | | |
| (millions) | Debt Principal Payments |
| 2018 | $ | — |
|
| 2019 | — |
|
| 2020 | 230 |
|
| 2021 | 1,464 |
|
| 2022 | — |
|
| Thereafter | 4,892 |
|
| Total | $ | 6,586 |
|
Note 11. Income Taxes
Recent Changes in US Tax LawReform LegislationOn December 22, 2017, the US Congress enacted the Tax Reform Legislation, which made significant changes to US federal income tax law, including a reduction in the federal corporate tax rate to 21% effective January 1, 2018. UnderThe 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 are required to recognizerecognized the effect of athe rate change on deferred tax assets and liabilities in the period in which the tax rate change is enacted. Therefore, the rate changewas enacted, by the Tax Reform Legislation resultedresulting 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.
Further, the Transition Tax (Toll Tax) Tax Reform Legislation providesprovided for a transitiontoll tax (toll tax) on a one-time “deemed repatriation” of accumulated foreign earnings for the year ended December 31, 2017. Based on currentearly interpretations of the law, we have recognized additional taxable income in 2017 of $767 million associated with the transitiontoll tax, which iswas fully offset by current year net operating
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
losses (NOLs), and have recorded corresponding deemed foreign tax credits of $164 million, against which we have 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
|
| | |
| 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 repealed corporate alternative minimumintroduced a new tax (AMT)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 tax years beginning January 1, 2018 GILTI associated with FORI from investments in operating assets in Equatorial Guinea and provides that existing AMT credit carryoversoperations in Israel. We are refundable beginning in 2018. We have approximately $3 million of AMT credit carryovers that are expectedmaking an accounting policy election to be fully refunded by 2022.not record deferred taxes related to GILTI.
In addition, the Tax Reform Legislation preserves deductibility of intangible drilling costs and provides for 100% bonus depreciation on tangible personal property expenditures through 2022. The bonus depreciation percentage is phased down from 100% beginning in 2023 to 0% for years after 2026.
The Other Provisions Tax Reform Legislation is a comprehensive bill containing other provisions such as limitations on the deductibility of interest expense and certain executive compensation, that aredo not expected to materially affect us. The ultimate impact of the Tax Reform Legislation may differ from our estimates due to changes in interpretations and assumptions made by us, as well asif additional regulatory guidance that may beis issued. We are closely monitoring the provision which revised and broadened the former Section 163(j) interest expense limitation rules. In particular, our estimatetax years subsequent to 2021 the basis of the impact of the toll tax is a provisional amount, based on current legal interpretations. This amount maylimitation calculation will change to be adjusted in future periods, asroughly equivalent to EBIT at which time we expect to be subject to an adjustmentinterest expense limitation. The interest expense not deducted due to income tax expense or benefit, in the period in which the final amounts are determined.limitation has an indefinite carryover period.
IncomeDeferred Tax Disclosures
Components of income (loss) from operations before income taxes are as follows: |
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| (millions) | | 2017 | | 2016 | | 2015 |
| Domestic | | $ | (2,831 | ) | | $ | (1,859 | ) | | $ | (2,338 | ) |
| Foreign | | 640 |
| | 87 |
| | 119 |
|
| Total | | $ | (2,191 | ) | | $ | (1,772 | ) | | $ | (2,219 | ) |
The income tax provision (benefit) consists of the following: |
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| (millions) | | 2017 | | 2016 | | 2015 |
| Current Taxes | | | | | | |
| Federal | | $ | (11 | ) | | $ | (4 | ) | | $ | (1 | ) |
| State | | 1 |
| | 5 |
| | — |
|
| Foreign | | 96 |
| | 196 |
| | 107 |
|
| Total Current | | $ | 86 |
| | $ | 197 |
| | $ | 106 |
|
| Deferred Taxes | | | | | | |
| Federal | | $ | (1,258 | ) | | $ | (784 | ) | | $ | 216 |
|
| State | | (8 | ) | | (24 | ) | | (5 | ) |
| Foreign | | 39 |
| | (176 | ) | | (95 | ) |
| Total Deferred | | $ | (1,227 | ) | | $ | (984 | ) | | $ | 116 |
|
| Total Income Tax (Benefit) Provision Attributable to Noble Energy | | $ | (1,141 | ) | | $ | (787 | ) | | $ | 222 |
|
| Effective Tax Rate | | 52.1 | % | | 44.4 | % | | (10.0 | )% |
|
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
A reconciliation of the federal statutory tax rate to the effective tax rate is as follows: |
| | | | | | | | | |
| | | Year Ended December 31, |
| (percentages) | | 2017 | | 2016 | | 2015 |
Federal Statutory Rate (1) | | 35.0 | % | | 35.0 | % | | 35.0 | % |
| Effect of | | | | | | |
| Earnings of Equity Method Investees | | 1.9 |
| | 1.0 |
| | 0.6 |
|
| Noncontrolling Interests | | 1.1 |
| | 0.4 |
| | — |
|
US and Foreign Statutory Rate Change (1) | | 23.5 |
| | 1.6 |
| | — |
|
Transition Tax (1) | | (4.8 | ) | | — |
| | — |
|
| State Taxes, Net of Federal Benefit | | 0.3 |
| | 1.3 |
| | 0.3 |
|
| Difference Between US and Foreign Rates | | 1.8 |
| | (0.1 | ) | | 2.6 |
|
| Foreign Exploration Loss | | — |
| | 0.1 |
| | 2.7 |
|
Change in Valuation Allowance (1) | | (17.4 | ) | | (2.0 | ) | | — |
|
| Oil Profits Tax - Israel | | (0.1 | ) | | — |
| | 0.1 |
|
| Tax Contingency | | 0.1 |
| | 0.2 |
| | 0.4 |
|
Accumulated Undistributed Foreign Earnings (1) | | 11.0 |
| | 7.2 |
| | (37.7 | ) |
| Goodwill Impairment | | — |
| | — |
| | (12.3 | ) |
| Other, Net | | (0.3 | ) | | (0.3 | ) | | (1.7 | ) |
| Effective Rate | | 52.1 | % | | 44.4 | % | | (10.0 | )% |
(1) See Recent Changes in US Tax Law, above. Rate will decrease to 21.0% for fiscal year 2018. In addition, see discussion regarding accumulated undistributed foreign earnings above.
Deferred tax assets and liabilities resulted from the following: |
| | | | | | | | |
| | | December 31, |
| (millions) | | 2017 | | 2016 |
| Deferred Tax Assets | | | | |
| Loss Carryforwards | | $ | 902 |
| | $ | 474 |
|
| Employee Compensation and Benefits | | 97 |
| | 150 |
|
| Mark to Market of Commodity Derivative Instruments | | 7 |
| | 44 |
|
| Foreign Tax Credits | | 366 |
| | — |
|
| Other | | 104 |
| | 49 |
|
| Total Deferred Tax Assets | | $ | 1,476 |
| | $ | 717 |
|
| Valuation Allowance - Foreign Loss Carryforwards and Foreign Tax Credits | | (549 | ) | | (242 | ) |
| Net Deferred Tax Assets | | $ | 927 |
| | $ | 475 |
|
| Deferred Tax Liabilities | | | | |
Accumulated Undistributed Foreign Earnings (1) | | — |
| | (240 | ) |
| Property, Plant and Equipment, Principally Due to Differences in Depreciation, Amortization, Lease Impairment and Abandonments | | (2,029 | ) | | (2,054 | ) |
| Total Deferred Tax Liability | | $ | (2,029 | ) | | $ | (2,294 | ) |
| Net Deferred Tax Liability | | $ | (1,102 | ) | | $ | (1,819 | ) |
(1) AtAssets Our estimated pre-tax NOL carryforwards totaled approximately $2.4 billion at December 31, 2017, we reversed the deferred tax liability associated with the removal2018, of the assertion of indefinitely reinvested earnings, resulting in recognition of a deferred tax benefit of $240 million.
Net deferred tax assets and liabilities were classified in the consolidated balance sheets as follows: |
| | | | | | | | |
| | | December 31, |
| (millions) | | 2017 | | 2016 |
| Deferred Income Tax Asset - Noncurrent | | $ | 25 |
| | $ | — |
|
| Deferred Income Tax Liability - Noncurrent | | (1,127 | ) | | (1,819 | ) |
| Net Deferred Tax Liability | | $ | (1,102 | ) | | $ | (1,819 | ) |
|
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Deferred Tax Assets Our estimatedwhich US federal income tax net operating loss (NOL)NOL carryforwards totaled approximately $3.2$1.7 billion at December 31, 2017. Included in the resulting deferred tax assets are acquired NOLs associated with the Clayton Williams Energy Acquisition in 2017 and the Rosetta Merger in 2015.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 $242$366 million in 2016. The changes to the valuation allowance for the loss carryforwards between periods was attributable to the offset2018 and 2017, respectively. As noted above, in first quarter 2018 we released $252 million of the valuation allowance recorded against the NOL in a jurisdiction in which we are no longer active. Deemed foreign tax credits of $164 million were recognized along with the additional taxable income associated with the transition tax. A full valuation allowance of $366 million has been recorded against all foreign tax creditsand in fourth quarter 2018, we made further return to provision adjustments based on current interpretation of the Tax Reform Legislation and the expected future utilization of NOL carryforwards.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. After the fair market valuation,Our purchase price allocation is finalized and we have currently recorded an opening balance sheeta deferred tax liability of $307$307 million,, adjusted for the new US statutory tax rate, which includes a deferred tax asset for federal pre-tax net operating lossesNOLs of approximately $450 million.$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 Subsidiaries In 2015, we changed our indefinite reinvestment assertion (APB 23 assertion) based on the continued and prolonged decline in global commodity prices and an evaluation of our operations’ anticipated capital requirements and projected foreign cash positions given the adoption of the Israel Natural Gas Framework in December 2015.
During 2016, we reviewed capital requirements and foreign cash positions, and reduced the deferred tax liability associated with unremitted foreign earnings, net of foreign tax credits, to $240 million as of December 31, 2016.
million. In 2017, as a result of Tax Reform Legislation, which establishesestablished a new territorial tax regime, we reversed the deferred tax liability recorded as of December 31,in 2016, was reversed, resulting in a deferred tax benefit of $240 million for the year endedmillion. As of December 31, 2017. We do not expect a2018, there is no expected withholding tax impact upon actual distribution of earnings and as such, we have not recorded any additional tax associated with the unremitted earnings.
Effective Tax Rate Our effective tax rate increased in 2017 as compared with 2016 primarily due to the recognition of a deferred tax benefit related to the Tax Reform Legislation. The deferred tax benefit resulted from the revaluation of the ending deferred tax liability at the reduced future tax rate and the transition to the new territorial tax regime.
Our effective tax rate increased in 2016 as compared with 2015 primarily due to adjustments to deferred taxes for removal of the APB 23 assertion, as noted above, decreased earnings in foreign jurisdictions with rates that vary from the US statutory rate, a decrease in the Israeli income tax rate, and the 2015 impact of foreign dividend repatriation and goodwill impairment.
Israeli Tax LawEffective December 21, 2016, the Israeli government decreased the corporate income tax rate from 25% to 24% for 2017 and announced a further rate decrease from 24% to 23% effective January 2018. The change decreasedfull impact of the rate reduction was recognized in 2017, decreasing deferred tax expense for 2017 by $12 million.$12 million.
Furthermore, our Israeli operations are subject to the Natural Resources Profits Taxation Law, 2011 (the Law), which imposes a separate additional tax on profits from oil and gas activities (Profits(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 Israeli tax purposes. Our Tamar and Leviathan projects are both subject to the Oil Profits Tax and are expected to pay at the maximum rate.
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
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 - 2014,2015, Israel - 2015 (2013 with respect to Israel Oil Profits Tax) and Equatorial Guinea - 2012.
2013. Our policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense.
A reconciliation As of our beginningDecember 31, 2018 and ending amounts of2017, we had no unrecognized tax benefits follows: |
| | | | |
| (millions) | | Twelve Months Ended December 31, 2017 |
| Unrecognized Tax Benefits, Beginning Balance | | $ | 3 |
|
| Reductions for Tax Positions of Prior Years | | (3 | ) |
| Unrecognized Tax Benefits, Ending Balance | | $ | — |
|
The changes to our unrecognized tax benefits during 2017 primarily resulted from changes in various foreign tax return filings, positions and audit settlements. The adjustments to our reserves for uncertain tax positions had a de minimis impact on our net income.
During 2017, we recognized and accrued a de minimis amount of interest and no penalties.benefits.
Note 12. Stock-Based13. Derivative Instruments and Other Compensation PlansHedging Activities
Objective and Strategies for Using Derivative InstrumentsWe recognized total stock-based compensation expense as follows: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, basis swaps, swaptions and/or put options. |
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| (millions) | | 2017 | | 2016 | | 2015 |
| Stock-Based Compensation Expense Included in: | | | | | | |
| General and Administrative Expense | | $ | 56 |
| | $ | 62 |
| | $ | 50 |
|
| Exploration Expense and Other | | 48 |
| | 15 |
| | 36 |
|
| Total Stock-Based Compensation Expense | | $ | 104 |
| | $ | 77 |
| | $ | 86 |
|
| Tax Benefit Recognized | | $ | (36 | ) | | $ | (27 | ) | | $ | (30 | ) |
Stock OptionThe fixed price swap and Restricted Stock PlansOur stock option and restricted stock plans are described below.
2017 Long-Term Incentive Plan On April 25, 2017, our stockholders approvedcollar contracts entitle us (floating price payor) to receive settlement from the Noble Energy, Inc. 2017 Long-Term Incentive Plan (the 2017 Plan). Upon stockholder approval,counterparty (fixed price payor) for each calculation period in amounts, if any, by which the 2017 Plan superceded and replacedsettlement price for the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan, as amended (the 1992 Plan) which was frozen so that no future grantsscheduled trading days applicable for each calculation period is less than the fixed strike price or floor price. We would be made underpay the 1992 Plan.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 1992 Plan continues to govern awards that were outstanding asamount payable by us, if the floating price is above the fixed or ceiling price, is the product of the date of its suspension, which remain in effect pursuant to their terms. Undernotional quantity per calculation period and the 2017 Plan, the Compensation, Benefits and Stock Option Committeeexcess of the Boardfloating price over the fixed or ceiling price in respect of Directors (the Committee)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 delta between the two put option strike prices. This type of instrument allows us to capture more value in a rising commodity price environment, but limits our benefits in a downward commodity price environment.
A swaption gives counterparties the right, but not the obligation, to enter into swap agreements with us on the option expiration dates.
While these instruments mitigate the cash flow risk of future reductions in commodity prices, they may grant stock options, stock appreciation rights, restricted stock, restricted stock units, performance awards, stock awardsalso curtail benefits during periods of increasing commodity prices.
See Note 14. Fair Value Measurements and other incentive awardsDisclosures for a discussion of methods and assumptions used to our officers or other employees and thoseestimate the fair values of our subsidiaries. The maximum numberderivative instruments. Counterparty Credit RiskDerivative instruments expose us to counterparty credit risk, especially during periods of shares thatfalling 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 granted underlimited in our ability to mitigate an increase in counterparty credit risk. Should one of these financial counterparties not perform, we may not realize the 2017 Plan is 29 million sharesbenefit of common stock. At December 31, 2017, 28,987,609 sharessome of our common stock were reserved for issuance, including 28,972,832 shares available for future grantsderivative instruments under lower commodity prices and awards, under the 2017 Plan.could incur a loss.
Stock options are issued with an exercise price equal to the fair market value of our common stock on the date of grant, and are subject to such other terms and conditions as may be determined by the Committee. Unless granted by the Committee for a shorter term, the options expire 10 years from the grant date. Option grants generally vest ratably over a three-year period.
Restricted stock awards made under the 2017 Plan are subject to such restrictions, terms and conditions, including forfeitures, if any, as may be determined by the Committee. During the period in which such restrictions apply, unless specifically provided otherwise in accordance with the terms of the 2017 Plan, the recipient of restricted stock would be the record owner of the shares and have all the rights of a stockholder with respect to the shares, including the right to vote and the right to receive dividends or other distributions made or paid with respect to the shares. The dividends or other distributions pertaining to the restricted shares will be held by the Company until the restriction period ends and the shares vest or forfeit. If the restricted shares forfeit, then the recipient shall not be entitled to receive the dividend or distribution, which will transfer to the Company. Restricted stock awards with a time-vested restriction vest over a two or three-year period. Performance share awards cliff vest after a three-year period if the Company achieves certain levels of total shareholder return relative to a pre-determined industry peer group.
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
2015 Stock Plan for Non-Employee Directors The 2015 Stock Plan for Non-Employee Directors of Noble Energy, Inc., as amended (the 2015 Plan) provides for grants of stock options and awards of restricted stock to our non-employee directors. The 2015 Plan superseded and replaced the 2005 Stock Plan for Non-Employee Directors of Noble Energy, Inc. The total number of shares of our common stock that may be issued under the 2015 Plan is 708,996. At December 31, 2017, 674,025 shares of our common stock were reserved for issuance, including 463,096 shares available for future grants and awards, under the 2015 Plan.
Stock Option Grants The fair value of each stock option granted is estimated on the date of grant using a Black-Scholes-Merton option valuation model that used the assumptions described below:
Expected termThe expected term represents the period of time that options granted are expected to be outstanding, which is the grant date to the date of expected exercise or other expected settlement for options granted. The hypothetical midpoint scenario we use considers our actual exercise and post-vesting cancellation history and expectations for future periods, which assumes that all vested, outstanding options are settled halfway between the current date and their expiration date.
Expected volatility The expected volatility represents the extent to which our stock price is expected to fluctuate between the grant date and the expected term of the award. We use the historical volatility of our common stock for a period equal to the expected term of the option prior to the date of grant. We believe that historical volatility produces an estimate that is representative of our expectations about the future volatility of our common stock over the expected term.
Risk-free rateThe risk-free rate is the implied yield available on US Treasury securities with a remaining term equal to the expected term of the option. We base our risk-free rate on a weighting of five and seven year US Treasury securities as of the date of grant.
Dividend yieldThe dividend yield represents the value of our stock’s annualized dividend as compared to our stock’s average price for the three-year period ended prior to the date of grant. It is calculated by dividing one full year of our expected dividends by our average stock price over the three-year period ended prior to the date of grant.
The assumptions used in valuing stock options granted were as follows: |
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| (weighted averages) | | 2017 | | 2016 | | 2015 |
| Expected Term (in Years) | | 6.4 |
| | 6.3 |
| | 6.0 |
|
| Expected Volatility | | 33.2 | % | | 32.4 | % | | 32.6 | % |
| Risk-Free Rate | | 2.2 | % | | 1.6 | % | | 1.4 | % |
| Expected Dividend Yield | | 0.9 | % | | 0.7 | % | | 1.2 | % |
| Weighted Average Grant-Date Fair Value | | $ | 13.26 |
| | $ | 10.10 |
| | $ | 13.93 |
|
Stock option activity was as follows: |
| | | | | | | | | | | | | |
| | | Options | | Weighted Average Exercise Price | | Weighted Average Remaining Contractual Term | | Aggregate Intrinsic Value |
| | | | | (per share) | | (in years) | | (in millions) |
| Outstanding at December 31, 2016 | | 15,088,862 |
| | $ | 43.49 |
| | | | |
| Granted | | 1,819,819 |
| | 39.40 |
| | | | |
| Exercised | | (382,882 | ) | | 37.57 |
| | | | |
| Forfeited | | (976,577 | ) | | 43.93 |
| | | | |
| Outstanding at December 31, 2017 | | 15,549,222 |
| | $ | 43.42 |
| | 5.0 | | $ | 6 |
|
| Exercisable at December 31, 2017 | | 12,101,890 |
| | $ | 44.98 |
| | 4.0 | | $ | 6 |
|
The total intrinsic value of options exercised was $4 million in 2017, $10 million in 2016 and $7 million in 2015.Unsettled Derivative Instruments As of December 31, 2017, $21 million2018, 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 | ) | — |
| | — |
| — |
| — |
|
| |
(1) | We have entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma. The weighted average differential represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes covered by the basis swap contracts. |
As of compensation cost relatedDecember 31, 2018, 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 | ) | — |
| | — |
| — |
| — |
|
(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 unvested stock options granted underestablish a fixed amount for the Plans remaineddifferential between index pricing for Colorado Interstate Gas and NYMEX Henry Hub. The weighted average differential represents the amount of reduction to be recognized. NYMEX Henry Hub prices for the notional volumes covered by the basis swap contracts.
Fair Value Amounts and Gains and Losses on Derivative InstrumentsThe cost is expected to be recognized over a weighted-average periodfair values of 1.3 years. We issue new shares ofderivative instruments on our common stock to settle option exercises. Dividends are not paid on unexercised options.
consolidated balance sheets were as follows (1):
127 |
| | | | | | | | | | | | | | | | | | | | | | | |
| | 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 |
|
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| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Restricted Stock Awards AwardsThe effect of time-vested restricted stock (shares subject to service conditions) are valued at the pricederivative instruments on our consolidated statements 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, |
| | 2017 | | 2016 | | 2015 |
| Number of Simulations | 500,000 |
| | 500,000 |
| | 500,000 |
|
| Expected Volatility | 35 | % | | 38 | % | | 30 | % |
| Risk-Free Rate | 1.5 | % | | 1.0 | % | | 0.8 | % |
Restricted stock activityoperations was as follows: |
| | | | | | | | | | | |
| | 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 |
|
|
| | | | | | | | | | | | | | |
| | | 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, 2016 | | 1,371,780 |
| | $ | 36.37 |
| | 1,502,992 |
| | $ | 27.43 |
|
Awarded (1) | | 3,201,504 |
| | 36.26 |
| | 464,608 |
| | 24.25 |
|
Vested (1) | | (2,515,383 | ) | | 34.93 |
| | (219,883 | ) | | 44.61 |
|
| Forfeited | | (218,164 | ) | | 37.66 |
| | (535,012 | ) | | 33.12 |
|
| Outstanding at December 31, 2017 | | 1,839,737 |
| | $ | 37.21 |
| | 1,212,705 |
| | $ | 25.55 |
|
| |
(1)
| During 2017, we awarded approximately 1.9 million shares of restricted stock for the conversion of Clayton Williams Energy shares into Noble Energy shares as part of the Clayton Williams Energy Acquisition. All awards subsequently vested during 2017. These awards are included in the above table. See Note 3. Clayton Williams Energy Acquisition. |
The total fair value of restricted stock that vested was $34 million in 2017, $24 million in 2016, and $62 million in 2015.
The weighted average award-date fair value of restricted stock awarded was $35.45 per share in 2017, $29.99 per share in 2016, and $35.53 per share in 2015.
As of December 31, 2017, $41 million of compensation cost related to all of our unvested restricted stock awarded under the Plans remained to be recognized. The cost is expected to be recognized over a weighted-average period of 1.4 years. Common stock dividends accrue on restricted stock awards and are paid upon vesting. We issue new shares of our common stock when awarding restricted stock.
Cash-Settled 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 (2-year cliff vesting for officers and 3-year cliff vesting for non-officers) or up to four times the fair market value of a share of common stock of the Company, which was $31.65, as of the grant date.
As of December 31, 2017, we had accrued a liability of $10 million related to the phantom units. No phantom units were awarded in 2017.
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Phantom unit activity was as follows: |
| | | | | | | | | | | | | | |
| | | Subject to Time Vesting | | Subject to Market Conditions |
| | | Number of Units | | Weighted
Average
Award Date
Fair Value | | Number of Units | | Weighted Average Award Date Fair Value |
| | | | | (per share) | | | | (per share) |
| Outstanding at December 31, 2016 | | 712,089 |
| | $ | 31.65 |
| | 209,504 |
| | $ | 6.82 |
|
| Vested | | (13,305 | ) | | 31.65 |
| | — |
| | — |
|
| Forfeited | | (88,625 | ) | | 31.65 |
| | (42,021 | ) | | 6.82 |
|
| Outstanding at December 31, 2017 | | 610,159 |
| | $ | 31.65 |
| | 167,483 |
| | $ | 6.82 |
|
As of December 31, 2017, $6 million of compensation cost related to phantom units remained to be recognized. The cost is expected to be recognized over a weighted-average period of 1.1 years. The total fair value of phantom units that vested in 2017 was de minimis. Common stock dividends accrue on phantom units and will be paid upon vesting.
Other Compensation Plans
401(k) PlanWe sponsor a 401(k) savings plan. All regular employees are eligible to participate. We make contributions to match employee contributions up to the first 6% of compensation deferred into the plan, and certain profit sharing contributions for employees hired on or after May 1, 2006, based upon their ages and salaries. We made cash contributions of $31 million in 2017, $32 million in 2016, and $35 million in 2015.
Deferred Compensation PlanWe have a non-qualified deferred compensation plan for which participant-directed investments are held in a rabbi trust and are available to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Participants in that nonqualified deferred compensation plan may elect to receive distributions in either cash or shares of our common stock. Components of that rabbi trust are as follows: |
| | | | | | | | |
| | | December 31, |
| (millions, except share amounts) | | 2017 | | 2016 |
| Rabbi Trust Assets | | | | |
| Mutual Fund Investments | | $ | 57 |
| | $ | 62 |
|
| Noble Energy Common Stock (at Fair Value) | | 14 |
| | 26 |
|
| Total Rabbi Trust Assets | | $ | 71 |
| | $ | 88 |
|
| Liability Under Related Deferred Compensation Plan | | $ | 71 |
| | $ | 88 |
|
| Number of Shares of Noble Energy Common Stock Held by Rabbi Trust | | 470,030 |
| | 671,269 |
|
Assets of that rabbi trust, other than our common stock, are invested in certain mutual funds that cover an investment spectrum ranging from equities to money market instruments. These mutual funds have published market prices and are reported at fair value. See Note 13. Fair Value Measurements and Disclosures. The mutual funds are included in the mutual fund investments account in other noncurrent assets in the consolidated balance sheets.Shares of our common stock held by the rabbi trust holding common stock are accounted for as treasury stock (recorded at cost, $16.72 per share) in the shareholders’ equity section of the consolidated balance sheets. Amounts payable to plan participants are included in other noncurrent liabilities in the consolidated balance sheets and include the market value of the shares of our common stock.
Approximately 400,000 shares, or 85%, of our common stock held in respect of one nonqualified deferred compensation plan at December 31, 2017 were attributable to a member of our Board of Directors. The shares are being distributed in equal installments over the next two years. Distributions of 200,000 shares were made in each of 2017, 2016 and 2015. In addition, plan participants sold 1,238 shares of our common stock in 2017, 1,009 shares in 2016, and 1,009 shares in 2015. Proceeds were invested in mutual funds and/or distributed to plan participants. Distributions to plan participants were valued at $21 million in 2017, $22 million in 2016 and $18 million in 2015.
All fluctuations in market value of the deferred compensation liability have been reflected in other non-operating (income) expense, net in the consolidated statements of operations. We recognized deferred compensation expense (income) of $9 million in 2017, $11 million in 2016 and $(12) million in 2015.
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
We also maintain other nonqualified deferred compensation plans for the benefit of certain of our employees. Deferred compensation liabilities of $116 million and $121 million were outstanding at December 31, 2017 and 2016, respectively, under those other plans.
Note 13.14. 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 inon 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 LIBOR rates, Eurodollar futures rates and interest swap rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. In addition, for collars, we estimate the option values of the put options sold and the contract floors and ceilings using an option pricing model which takes into accountconsiders market volatility, market prices and contract terms. See Note 8.13. Derivative Instruments and Hedging Activities. Deferred Compensation Liability The value is dependent upon the fair values of mutual fund investments and shares of our common stock held in a rabbi trust.See Mutual Fund Investments above.
Stock-Based Compensation Liability A portion of the value of the liability associated with our phantom unit plan is dependent upon the fair value of Noble Energy common stock as of the end of each reporting period. See Note 12.17. Stock-Based and Other Compensation Plans.
|
| | |
| 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 | | | | | 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 | 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 |
| $ | 57 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 57 |
|
| Commodity Derivative Instruments | — |
| | 7 |
| | — |
| | (5 | ) | | 2 |
| — |
| | 7 |
| | — |
| | (5 | ) | | 2 |
|
| Financial Liabilities | | | | | | | | | | | | | | | | | | |
| Commodity Derivative Instruments | — |
| | (78 | ) | | — |
| | 5 |
| | (73 | ) | — |
| | (78 | ) | | — |
| | 5 |
| | (73 | ) |
| Portion of Deferred Compensation Liability Measured at Fair Value | (71 | ) | | — |
| | — |
| | — |
| | (71 | ) | (71 | ) | | — |
| | — |
| | — |
| | (71 | ) |
| Stock Based Compensation Liability Measured at Fair Value | (10 | ) | | — |
| | — |
| | — |
| | (10 | ) | (10 | ) | | — |
| | — |
| | — |
| | (10 | ) |
| December 31, 2016 | | | | | | | |
| | |
| |
| Financial Assets | |
| | |
| | |
| | |
| | |
| |
| Mutual Fund Investments | $ | 71 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 71 |
| |
| Commodity Derivative Instruments | — |
| | 5 |
| | — |
| | (5 | ) | | — |
| |
| Financial Liabilities | | | | | | | | | | |
| Commodity Derivative Instruments | — |
| | (121 | ) | | — |
| | 5 |
| | (116 | ) | |
| Portion of Deferred Compensation Liability Measured at Fair Value | (88 | ) | | — |
| | — |
| | — |
| | (88 | ) | |
| Stock Based Compensation Liability Measured at Fair Value | (9 | ) | | — |
| | — |
| | — |
| | (9 | ) | |
| |
(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 inon our consolidated balance sheets. The followingSee Note 1. Summary of Significant Accounting Policies for the methods and assumptions were used to estimate the fair values: Asset ImpairmentsIn 2017, 2016, and 2015,Impairments are recorded when we determineddetermine that the carrying amounts of certain oil and gas assets wereproperties or midstream facilities are not recoverable from future cash flows, and therefore,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 impaired.not selected. The assets were reduced to their estimated fair values as noted below.values.
Inventory Impairment In 2016, and 2015, we determined that the carrying amount of certain of our materials and supplies inventory was greater than its net realizable value, or not recoverable from future cash flows. These assets were, therefore, adjusted as noted below.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 As of December 31, In 2017,, we had recorded a $90liabilities totaling $93 million liability representing the discounted present value of our remaining obligation under certain firm transportation contracts. See Note 17 –10. Marcellus Shale Firm Transportation Commitments and Contingencies.
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Information about the impaired assets is as follows: |
| | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using | | | | |
| Description | Quoted Prices in Active Markets (Level 1) (1) | | Significant Other Observable Inputs (Level 2) (1) | | Significant Unobservable Inputs (Level 3) (1) | | Net Book Value (2) | | Total Pre-tax (Non-cash) Impairment Loss |
| (millions) | | | | | | | | | |
| Year Ended December 31, 2017 | | | | | | | | |
| Impaired Oil and Gas Properties | $ | — |
| | $ | — |
| | $ | — |
| | $ | 70 |
| | $ | 70 |
|
| Year Ended December 31, 2016 | | | | | | | | |
| Impaired Oil and Gas Properties | — |
| | — |
| | — |
| | 92 |
| | 92 |
|
| Impaired Materials and Supplies Inventory | — |
| | — |
| | 91 |
| | 105 |
| | 14 |
|
| Year Ended December 31, 2015 | | | | | | | | |
| Impaired Oil and Gas Properties | — |
| | — |
| | 752 |
| | 1,285 |
| | 533 |
|
| Impaired Materials and Supplies Inventory | — |
| | — |
| | 61 |
| | 81 |
| | 20 |
|
| |
(2)
| Amount represents net book value at the date of assessment. |
The fair values of properties held and used were determined as of the date of the assessment using discounted cash flow models. The discounted cash flows were based on management’s expectations for the future. Inputs included estimates of future crude oil and natural gas production, commodity prices based on commodities sales contract terms or commodity price curves as of the date of the estimate, estimated operating and development costs, and a risk-adjusted discount rate of 10%. The fair values of assets held for sale were based on anticipated sales proceeds less costs to sell. Costs associated with abandoned properties were completely written off. See Note 5. Asset Impairments.
Additional Fair Value Disclosures
Debt The fair value of fixed-rate, public debt is estimated based on the published market prices for the same or similar issues. As such, we consider the fair value of our public, fixed-rate debt to be a Level 1 measurement on the fair value hierarchy.
At December 31, 2017,2018, our variable-rate, non-public debt included the Revolving Credit Facility, Noble Midstream Services Revolving Credit Facility and the Noble Midstream Services RevolvingTerm 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 10.9. 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 |
|
|
| | | | | | | | | | | | | | | |
| | December 31,
2017 | | December 31,
2016 |
| (millions) | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
Long-Term Debt, Net (1) | $ | 6,586 |
| | $ | 7,142 |
| | $ | 6,739 |
| | $ | 7,112 |
|
Note 15. Equity Method Investments
Equity Method Investments Investments accounted for under the equity method consist primarily of the following:
| |
(1)
• | Excludes unamortized discount, premium, debt issuance costs |
45% interest in Atlantic Methanol Production Company, LLC (AMPCO), which owns and operates a methanol plant and related facilities in Equatorial Guinea; and Note 14. Segment Information28% interest in Alba Plant , which owns and operates a LPG processing plant in Equatorial Guinea.
During second quarter 2017,We consider these equity method investments essential components of our business as a resultwell as necessary and integral elements of the strategic changesour value chain in support of ongoing operations in our US onshore portfolio, we established our Midstream business as a new reportable segment. The Midstream segment, which includesand West Africa segments. For the consolidated accounts ofAdvantage Pipeline system, Noble Midstream Partners additional US onshore midstream assetsserves as operator and US onshoreexerts 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 investments, was previously reported within the United States reportable segment. As a result, we now have the following reportable segments: United States (US onshore and Gulf of Mexico); Eastern Mediterranean (Israel and Cyprus); West Africa (Equatorial Guinea, Cameroon and Gabon); Other International (Newfoundland (Canada), Suriname, Falkland Islands and new ventures); and Midstream.investees.
The geographical reportable segments are incarrying value of our AMPCO investment was $13 million higher than the businessunderlying net assets of crude oil and natural gas exploration, development, production, and acquisition (Oil and Gas Exploration and Production or E&P).the investee at December 31, 2018. The Midstream reportable segment owns, operates, develops and acquires domestic midstream infrastructure assets with current focus areas being the DJ and Delaware Basins. Expensesdifference is related to debt, headquarters depreciation and corporate general and administrative expenses are recorded atcapitalized interest which is being amortized into earnings over the corporate level. Priorremaining useful life of the plant.
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
period amounts are presented on a comparable basis.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 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Oil and Gas Exploration and Production | | Midstream | | |
| (In millions) | Consolidated | | United
States | | Eastern
Mediter- ranean | | West
Africa | | Other Int'l | | United States | | Intersegment Eliminations and Other (1) | | Corporate |
| Year Ended December 31, 2017 | | | | | | | | | | | | | | |
Oil, NGL and Gas Sales from Third Parties (2) | $ | 4,060 |
| | $ | 3,156 |
| | $ | 534 |
| | $ | 370 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Income from Equity Method Investees and Other (3) | 196 |
| | — |
| | — |
| | 120 |
| | — |
| | 76 |
| | — |
| | — |
|
| Intersegment Revenues | — |
| | — |
| | — |
| | — |
| | — |
| | 277 |
| | (277 | ) | | — |
|
| Total Revenues | 4,256 |
| | 3,156 |
| | 534 |
| | 490 |
| | — |
| | 353 |
| | (277 | ) | | — |
|
| Lease Operating Expense | 571 |
| | 466 |
| | 29 |
| | 90 |
| | — |
| | — |
| | (14 | ) | | — |
|
| Production and Ad Valorem Taxes | 138 |
| | 135 |
| | — |
| | — |
| | — |
| | 3 |
| | — |
| | — |
|
| Gathering, Transportation and Processing Expense | 432 |
| | 550 |
| | — |
| | — |
| | — |
| | 70 |
| | (188 | ) | | — |
|
| Total Production Expense | 1,141 |
| | 1,151 |
| | 29 |
| | 90 |
| | — |
| | 73 |
| | (202 | ) | | — |
|
| DD&A | 2,053 |
| | 1,739 |
| | 76 |
| | 146 |
| | 4 |
| | 30 |
| | (5 | ) | | 63 |
|
| Clayton Williams Energy Acquisition Expenses | 100 |
| | 100 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Loss on Debt Extinguishment | 98 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 98 |
|
| Loss on Marcellus Shale Upstream Divestiture | 2,379 |
| | 2,379 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Asset Impairments | 70 |
| | 63 |
| | — |
| | — |
| | 7 |
| | — |
| | — |
| | — |
|
| Gain on Commodity Derivative Instruments | (63 | ) | | (92 | ) | | — |
| | 29 |
| | — |
| | — |
| | — |
| | — |
|
| (Loss) Income Before Income Taxes | (2,191 | ) | | (2,365 | ) | | 413 |
| | 203 |
| | (54 | ) | | 233 |
| | (62 | ) | | (559 | ) |
| Equity Method Investments | 305 |
| | — |
| | �� |
| | 225 |
| | — |
| | 80 |
| | — |
| | — |
|
| Additions to Long Lived Assets | 2,851 |
| | 1,994 |
| | 411 |
| | 34 |
| | (34 | ) | | 423 |
| | (79 | ) | | 102 |
|
Goodwill (4) | 1,310 |
| | 1,310 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total Assets at End of Year (5) | 21,476 |
| | 15,767 |
| | 2,846 |
| | 1,308 |
| | 114 |
| | 1,357 |
| | (163 | ) | | 247 |
|
| Year Ended December 31, 2016 | | |
| | |
| | |
| | | | | | | | |
|
Oil, NGL and Gas Sales from Third Parties (2) | $ | 3,389 |
| | $ | 2,416 |
| | $ | 540 |
| | $ | 433 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Income from Equity Method Investees and Other | 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 | 78 |
| | 76 |
| | — |
| | — |
| | — |
| | 2 |
| | — |
| | — |
|
| Gathering, Transportation and Processing Expense | 480 |
| | 564 |
| | — |
| | — |
| | — |
| | 44 |
| | (128 | ) | | — |
|
| Total Production Expense | 1,100 |
| | 1,058 |
| | 37 |
| | 105 |
| | — |
| | 46 |
| | (146 | ) | | — |
|
| DD&A | 2,454 |
| | 2,103 |
| | 81 |
| | 205 |
| | 6 |
| | 19 |
| | — |
| | 40 |
|
| Asset Impairments | 92 |
| | — |
| | 88 |
| | — |
| | 4 |
| | — |
| | — |
| | — |
|
| Loss on Commodity Derivative Instruments | 139 |
| | 126 |
| | — |
| | 13 |
| | — |
| | — |
| | — |
| |
|
|
| (Loss) Income Before Income Taxes | (1,772 | ) | | (1,277 | ) | | 543 |
| | (338 | ) | | (199 | ) | | 176 |
| | (51 | ) | | (626 | ) |
| Equity Method Investments | 400 |
| | — |
| | — |
| | 217 |
| | — |
| | 183 |
| | — |
| | — |
|
| Additions to Long Lived Assets | 1,526 |
| | 1,353 |
| | 88 |
| | 54 |
| | (6 | ) | | 58 |
| | (53 | ) | | 32 |
|
Total Assets at End of Year (5) | 21,011 |
| | 16,153 |
| | 2,233 |
| | 1,479 |
| | 89 |
| | 851 |
| | (98 | ) | | 304 |
|
|
| | | | | | | | | | | | |
| | | 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 |
|
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Oil and Gas Exploration and Production | | Midstream | | |
| (In millions) | Consolidated | | United
States | | Eastern
Mediter- ranean | | West
Africa | | Other Int'l | | United States | | Intersegment Eliminations and Other (1) | | Corporate |
| Year Ended December 31, 2015 |
Oil, NGL and Gas Sales from Third Parties (2) | $ | 3,093 |
| | $ | 2,011 |
| | $ | 497 |
| | $ | 580 |
| | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Income from Equity Method Investees and Other | 90 |
| | — |
| | — |
| | 39 |
| | — |
| | 51 |
| | — |
| | — |
|
| Intersegment Revenues | — |
| | — |
| | — |
| | — |
| | — |
| | 119 |
| | (119 | ) | | — |
|
| Total Revenues | 3,183 |
| | 2,011 |
| | 497 |
| | 619 |
| | 5 |
| | 170 |
| | (119 | ) | | — |
|
| Lease Operating Expense | 563 |
| | 398 |
| | 42 |
| | 131 |
| | 4 |
| | — |
| | (12 | ) | | — |
|
| Production and Ad Valorem Taxes | 127 |
| | 126 |
| | — |
| | — |
| | — |
| | 1 |
| | — |
| | — |
|
| Gathering, Transportation and Processing Expense | 306 |
| | 366 |
| | — |
| | — |
| | — |
| | 25 |
| | (85 | ) | | — |
|
| Total Production Expense | 996 |
| | 890 |
| | 42 |
| | 131 |
| | 4 |
| | 26 |
| | (97 | ) | | — |
|
| DD&A | 2,131 |
| | 1,677 |
| | 70 |
| | 326 |
| | — |
| | 14 |
| | — |
| | 44 |
|
| Asset Impairments | 533 |
| | 158 |
| | 36 |
| | 339 |
| | — |
| | — |
| | — |
| | — |
|
| Gain on Commodity Derivative Instruments | (501 | ) | | (347 | ) | | — |
| | (154 | ) | | — |
| | — |
| | — |
| | — |
|
| (Loss) Income Before Income Taxes | (2,219 | ) | | (1,693 | ) | | 313 |
| | (90 | ) | | (229 | ) | | 123 |
| | (21 | ) | | (622 | ) |
| Equity Method Investments | 453 |
| | — |
| | — |
| | 227 |
| | — |
| | 226 |
| | — |
| | — |
|
| Additions to Long Lived Assets | 3,062 |
| | 2,409 |
| | 147 |
| | 124 |
| | 177 |
| | 146 |
| | (21 | ) | | 80 |
|
Total Assets at End of Year (5) | 24,196 |
| | 18,043 |
| | 2,676 |
| | 2,299 |
| | 205 |
| | 799 |
| | (46 | ) | | 220 |
|
| |
(1)
| Intersegment eliminations related to (loss) income before income taxes are the result of Midstream expenditures. These costs are presented as property, plant and equipment within the E&P business on an unconsolidated basis, in accordance with the successful efforts method of accounting, and are eliminated upon consolidation. |
(2) Revenues from third parties for all foreign countries, in total, were $904 million in 2017, $973 million in 2016, and $1.1 billion in 2015.
(3) The midstream segment includes revenues of $19 million from third party customers.
(5) Long-lived assets located in all foreign countries, in total, were $2.8 billion, $3.0 billion, and $3.9 billion at December 31, 2017, 2016, and 2015, respectively.
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Note 15. Concentration of Risk
Concentration of Market Risk The largest single non-affiliated purchasers of our production were as follows: |
| | | | | | |
| | | Percentage of Crude Oil Sales | | Percentage of Total Oil, Gas & NGL Sales |
| 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 | % |
| Year Ended December 31, 2015 | | | | |
| Glencore Energy UK Ltd | | 30 | % | | 18 | % |
Shell (2) | | 18 | % | | 11 | % |
(1) Includes sales to BP North American Funding Company, BP Company Commercial and/or BP Company.
(2) Includes sales to Shell Trading (US) Company and/or Shell International Trading and Shipping Limited.
We believe the loss of any one purchaser would not have a material effect on our financial position or results of operations since there are numerous potential purchasers of our production.
Concentration of Credit Risk Certain of our financial instruments, including cash equivalents, trade and joint interest receivables and derivative instruments, may expose us to credit risk.
A significant portion of our cash is located in our foreign subsidiaries. The cash is denominated in US dollars and invested in highly liquid money market funds and short term deposits with original maturities of three months or less at the time of purchase. Although our cash and cash equivalents are deposited with major international banks and financial institutions, concentrations of cash in certain foreign locations may increase credit risk. We monitor the creditworthiness of the banks and financial institutions with which we invest and review the securities underlying our investment accounts. We believe that losses from nonperformance are unlikely to occur; however, we are not able to predict sudden changes in creditworthiness.
Our accounts receivable result from sales of crude oil, NGL and natural gas production, and joint interest billings to our partners for their share of expenses on joint venture projects for which we are the operator. Joint venture projects, especially in deepwater or remote international locations, can be very capital cost intensive. Thus the receivables from our joint venture partners can become significant.
Our accounts receivable reflect a broad national and international customer base, which limits our exposure to concentrations of credit risk. The majority of these receivables have payment terms of 30 days or less. We continually monitor the creditworthiness of the counterparties, some of which are not as creditworthy as we are and may experience liquidity problems. We have obtained credit enhancements from some parties, including one of our significant crude oil purchasers, in the way of parental guarantees or letters of credit. However, we do not have all of our trade credit or joint interest receivables protected through guarantees or credit support. Nonperformance by a trade creditor or joint venture partner could result in losses.
Our hedging activity may increase counterparty credit risk, especially during periods of falling commodity prices. We conduct our hedging activities with a diverse group of investment grade major banks and market participants. We monitor the creditworthiness of our hedge counterparties, and our internal hedge policies provide for mark-to-market exposure limits. We use master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be “net settled” at the time of election.
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
Note 16. Additional Shareholders’ Equity Information
Common Stock and Treasury Stock Activity in shares of our common stock and treasury stock was as follows: |
| | | | | | |
| | | Year Ended December 31, |
| | | 2018 | | 2017 |
| Shares of Common Stock Issued | | |
| | |
|
| Shares, Beginning of Period | | 528,743,381 |
| | 471,360,427 |
|
| Exercise of Common Stock Options | | 576,617 |
| | 382,882 |
|
Restricted Stock Awarded, Net of Forfeitures (1) | | 2,488,363 |
| | 2,912,936 |
|
Purchase and Retirement of Common Stock (2) | | (10,008,128 | ) | | — |
|
| Shares Exchanged in Clayton Williams Energy Acquisition | | (745,232 | ) | | 54,087,136 |
|
| Shares, End of Period | | 521,055,001 |
| | 528,743,381 |
|
| Treasury Stock | | | | |
| Shares, Beginning of Period | | 38,786,969 |
| | 37,961,316 |
|
Shares Received in Payment of Withholding Taxes Due on Vesting of Shares of Restricted Stock (3) | | 267,258 |
| | 1,026,891 |
|
| Rabbi Trust Shares Distributed and/or Sold | | (202,239 | ) | | (201,238 | ) |
| Shares, End of Period | | 38,851,988 |
| | 38,786,969 |
|
| 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) | | 15,004,591 |
| | 15,619,276 |
|
|
| | | | | | |
| | | Year Ended December 31, |
| | | 2017 | | 2016 |
| Common Stock Shares Issued | | |
| | |
|
| Shares, Beginning of Period | | 471,360,427 |
| | 469,718,512 |
|
| Exercise of Common Stock Options | | 382,882 |
| | 954,898 |
|
Restricted Stock Awarded, Net of Forfeitures (1) | | 2,912,936 |
| | 687,017 |
|
| Shares Exchanged in Clayton Williams Energy Acquisition | | 54,087,136 |
| | — |
|
| Shares, End of Period | | 528,743,381 |
| | 471,360,427 |
|
| Treasury Stock | |
|
| |
|
|
| Shares, Beginning of Period | | 37,961,316 |
| | 37,925,625 |
|
Shares Received in Payment of Withholding Taxes Due on Vesting of Shares of Restricted Stock (2) | | 1,026,891 |
| | 236,700 |
|
| Rabbi Trust Shares Distributed and/or Sold | | (201,238 | ) | | (201,009 | ) |
| Shares, End of Period | | 38,786,969 |
| | 37,961,316 |
|
| Additional Information | | | | |
Incremental Shares From Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust (2) | | — |
| | — |
|
| Number of Antidilutive Stock Options, Shares of Restricted Stock and Shares of Common Stock in Rabbi Trust excluded from Dilutive Loss per Share | | 15,619,276 |
| | 14,218,319 |
|
| |
(1) | The 2017 amount includes approximately 1.9 million shares of restricted stock awarded to former holders of Clayton Williams Energy outstanding stock awards as part of the Clayton Williams Energy Acquisition. See Note 3. Clayton Williams Energy Acquisition. |
| |
(2) | 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. These 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. |
| |
(3)(4)
| For the years ended December 31, 20172018 and 2016,2017, all outstanding options and non-vested restricted shares have been excluded from the calculation of diluted earnings (loss) per share as Noble Energy incurred a loss. Therefore, inclusion of outstanding options and non-vested restricted shares in the calculation of diluted earnings (loss) per share would be anti-dilutive. |
Issuance of Noble Midstream Partners Common UnitsOn December 15, 2017, Noble Midstream Partners closed an offering of 3,680,000 common units, generating net proceeds of approximately $174 million, net of offering costs. On June 26, 2017, Noble Midstream Partners engaged in a private placement offering of 3,525,000 common units, generating proceeds of approximately $138 million, net of offering costs.
In third quarter 2016, Noble Midstream Partners completed its initial public offering of 14,375,000 common units, generating proceeds of $299 million, net of offering costs.115
Subsequent Event - Share Repurchase Program On February 15, 2018, we announced the Company's Board of Directors authorized a share repurchase program of $750 million which expires December 31, 2020. All purchases will be made in accordance with applicable securities laws from time to time in open market or private transactions, depending on market conditions, and may be discontinued at any time. |
| | |
| 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 |
| 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 | ) |
| Realized Amounts Reclassified Into Earnings | | 1 |
| | 4 |
| | 5 |
|
| Unrealized Change in Fair Value | | — |
| | (4 | ) | | (4 | ) |
| December 31, 2017 | | (20 | ) | | (10 | ) | | (30 | ) |
| Realized Amounts Reclassified Into Earnings | | (3 | ) | | 1 |
| | (2 | ) |
| Unrealized Change in Fair Value | | — |
| | — |
| | — |
|
| December 31, 2018 | | $ | (23 | ) | | $ | (9 | ) | | $ | (32 | ) |
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
|
| | | | | | | | | | | | |
| | Accumulated Other Comprehensive Loss |
| (millions) | | Interest Rate Cash Flow Hedges | | Pension- Related and Other | | Total |
| December 31, 2014 | | $ | (23 | ) | | $ | (67 | ) | | $ | (90 | ) |
| Realized Amounts Reclassified Into Earnings | | 1 |
| | 62 |
| | 63 |
|
| Unrealized Change in Fair Value | | — |
| | (6 | ) | | (6 | ) |
| 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 | ) |
| Realized Amounts Reclassified Into Earnings | | 1 |
| | 4 |
| | 5 |
|
| Unrealized Change in Fair Value | | — |
| | (4 | ) | | (4 | ) |
| December 31, 2017 | | $ | (20 | ) | | $ | (10 | ) | | $ | (30 | ) |
All amountsItems in the table above are reportedAOCL 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, 20172018 included deferred losses of $20$24 million, net of tax, related to an interest rate derivative instruments.instrument. This amount is being reclassified to earnings as an adjustment to interest expense over the term of our senior notes due March 2041.
Note 17. CommitmentsStock-Based and ContingenciesOther Compensation Plans
Legal ProceedingsWe recognized total stock-based compensation expense as follows: |
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| (millions) | | 2018 | | 2017 | | 2016 |
| Stock-Based Compensation Expense Included in: | | | | | | |
| General and Administrative Expense | | $ | 54 |
| | $ | 56 |
| | $ | 62 |
|
| Exploration Expense and Other | | 8 |
| | 48 |
| | 15 |
|
| Total Stock-Based Compensation Expense | | $ | 62 |
| | $ | 104 |
| | $ | 77 |
|
| Tax Benefit Recognized | | $ | (13 | ) | | $ | (36 | ) | | $ | (27 | ) |
Stock Option and Restricted Stock PlansOur stock option and restricted stock plans are involveddescribed 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 various legal proceedings ineffect pursuant to their terms. Under the ordinary course2017 Plan, the Compensation, Benefits and Stock Option Committee of business. These proceedingsthe Board of Directors (the Committee) may grant stock options, stock appreciation rights, restricted stock, restricted stock units, performance awards, stock awards and other incentive awards to our officers or other employees and those of our subsidiaries. The maximum number of shares that may be granted under the 2017 Plan is 29 million shares of common stock. At December 31, 2018, 26,621,632 shares of our common stock were reserved for issuance, including 21,084,928 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 the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such mattersother terms and we believe that the ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations or cash flows.
Colorado Air Matter In April 2015, we entered into a joint consent decree (Consent Decree) with the US Environmental Protection Agency, US Department of Justice, and State of Colorado to improve emission control systems at a number of our condensate storage tanks that are part of our upstream crude oil and natural gas operations within the Non-Attainment Area of the DJ Basin. The Consent Decree was enteredconditions as may be determined by the US District CourtCommittee. Unless granted by the Committee for a shorter term, the District of Colorado on June 2, 2015.options expire 10 years from the grant date. Option grants generally vest ratably over a three-year period.
The Consent Decree,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 alleges violations of the Colorado Air Pollution Prevention and Control Act and Colorado’s federal approved State Implementation Plan,such restrictions apply, unless specifically Colorado Air Quality Control Commission Regulation Number 7, requires us to perform certain injunctive relief activities and to complete mitigation projects and supplemental environmental projects (SEP), and pay a civil penalty. Costs associated with the settlement consist of $4.95 million in civil penalties which were paid in 2015. Mitigation costs of $4.5 million and SEP costs of $4 million are being expendedprovided otherwise in accordance with schedules established in the Consent Decree. Costs associated with the injunctive relief are also being expended in accordance with schedules established in the Consent Decree. Over the last three years, 2015 through 2017, we spent approximately $72.0 million to undertake injunctive relief at certain tank systems following the outcome of adequacy of design evaluations and certain operation and maintenance activities to handle potential peak instantaneous vapor flow rates. Future costs associated with injunctive relief are not yet precisely quantifiable as we are continually evaluating various approaches to meet the ongoing obligationsterms of the Consent Decree.
Overall compliance with2017 Plan, the Consent Decree has resulted inrecipient of restricted stock would be the temporary shut-in and permanent plugging and abandonment of certain wells and associated tank batteries. Consent Decree compliance could result in additional temporary shut-ins and permanent plugging and abandonment of certain wells and associated tank batteries. The Consent Decree sets forth a detailed compliance schedule with deadlines for achievement of milestones through early 2019 that may be extended depending on certain situations. The Consent Decree contains additional obligations for ongoing inspection and monitoring beyond that which is required under existing Colorado regulations.
We have concluded that the penalties, injunctive relief, and mitigation expenditures that resulted from this settlement did not have, and based on currently available information will not have, a material adverse effect on our financial position, results of operations or cash flows.
Colorado Water Quality Control Division Matter In January 2017, we received a Notice of Violation/Cease and Desist Order (NOV/CDO) advising us of alleged violationsrecord owner of the Colorado Water Quality Control Act (Act)shares and its implementing regulations as it relateshave all the rights of a shareholder with respect to our Colorado Discharge Permit System General Permit for construction activities associatedthe shares, including the right to vote and the right to receive dividends or other distributions made or paid with oilrespect 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 gas exploration and/the shares vest or production within our Wells Ranch Drilling and Production field located in Weld County, Coloradoforfeit. 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 | |
(Permit).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 NOV/CDO further orders us to cease and desist from all violations2015 Stock Plan for Non-Employee Directors of the Act, the regulations and the Permit and to undertake certain corrective actions. Given the uncertainty associated with administrative actions of this nature, we are unable to predict the ultimate outcome of this action at this time but believe that the resolution of this action will not have a material adverse effect on our financial position, results of operations or cash flows.
Colorado Oil & Gas Conservation Commission Administrative Order on Consent In November 2017, we received a proposed Administrative Order on Consent (AOC) from the COGCC to resolve allegations of noncompliance associated with site preparation and stabilization at an oil and gas location in Weld County, Colorado. The AOC, whichNoble Energy, Inc., as amended (the 2015 Plan) provides for an opportunitygrants of stock options and awards of restricted stock to further discussour non-employee directors. The 2015 Plan superseded and replaced the offer2005 Stock Plan for Non-Employee Directors of settlement, has not yet been executed. Given the uncertainty associated with administrative actionsNoble Energy, Inc. The total number of this nature, we are unable to predict the ultimate outcome of this action at this time but believe that the resolution of this action will not have a material adverse effect on our financial position, results of operations or cash flows.
Colorado Air Compliance Order on Consent In April 2017, we received a proposed Compliance Order on Consent (COC) from the Colorado Department of Public Health and Environment’s Air Pollution Control Division (APCD) to resolve allegations of noncompliance associated with compliance testing of certain engines subject to various General Permit 02 conditions and/or individual permit conditions. In May 2017, we reached a final resolution with the APCD and executed the COC, which requires payment of a civil penalty of $24,710 and an expenditure of no less than $98,840 on an approved SEP(s). This resolution is not believed to have a material adverse effect on our financial position, results of operations or cash flows.
Transportation and Gathering Obligations As partshares 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 ofcommon stock that may be issued under the Marcellus Basin. Our financial commitment for these agreements, which have remaining terms of two to 16 years,2015 Plan is approximately $1.4 billion, undiscounted. The agreements for firm transportation primarily relate to services on certain pipelines which were recently placed into service in late 2017/early 2018 or for services on new pipeline projects to be constructed by, and connecting to, existing and new interstate pipeline systems with estimated in-service dates in late 2018. The associated commitments are included in the table below. See Note 1. Summary of Significant Accounting Policies – Exit Costs.We also have transportation and gathering obligations to flow DJ Basin, Eagle Ford Shale, and Gulf of Mexico production to various markets. Our financial commitment for these agreements, which have remaining terms of one to 11 years, is approximately $781 million, undiscounted. The commitment is included in the table below.
Non-Cancelable Leases and Other Commitments 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 $69 million in 2017, $76 million in 2016, and $84 million in 2015.
Minimum commitments as of708,996. At December 31, 2017 consist2018, 576,798 shares of our common stock were reserved for issuance, including 397,979 shares available for future grants and awards, under the following:2015 Plan. |
| | | | | | | | | | | | | | | | | | | | |
| (millions) | | Drilling, Equipment, and Purchase Obligations | | Transportation and Gathering Obligations | | Operating Lease Obligations | | Capital Lease and Other Obligations(1) | | Total |
| 2018 | | $ | 636 |
| | $ | 215 |
| | $ | 44 |
| | $ | 74 |
| | $ | 969 |
|
| 2019 | | 167 |
| | 252 |
| | 33 |
| | 45 |
| | 497 |
|
| 2020 | | 40 |
| | 247 |
| | 32 |
| | 42 |
| | 361 |
|
| 2021 | | 13 |
| | 223 |
| | 32 |
| | 29 |
| | 297 |
|
| 2022 | | 8 |
| | 182 |
| | 33 |
| | 21 |
| | 244 |
|
| 2023 and Thereafter | | 32 |
| | 1,355 |
| | 156 |
| | 124 |
| | 1,667 |
|
| Total | | $ | 896 |
| | $ | 2,474 |
| | $ | 330 |
| | $ | 335 |
| | $ | 4,035 |
|
| |
(1)
• | Annual lease payments, netExpected termThe expected term represents the period of time that options granted are expected to be outstanding, which is the grant date to the date of expected exercise or other expected settlement for options granted. The hypothetical midpoint scenario we use considers our actual exercise and post-vesting cancellation history and expectations for future periods, which assumes that all vested, outstanding options are settled halfway between the current date and their expiration date.
|
| |
| • | Expected volatility The expected volatility represents the extent to which our stock price is expected to fluctuate between the grant date and the expected term of the award. We use the historical volatility of our common stock for a period equal to the expected term of the option prior to the date of grant. We believe that historical volatility produces an estimate that is representative of our expectations about the future volatility of our common stock over the expected term. |
| |
| • | Risk-free rateThe risk-free rate is the implied yield available on US Treasury securities with a remaining term equal to the expected term of the option. We base our risk-free rate on a weighting of five and seven year US Treasury securities as of the date of grant. |
| |
| • | Dividend yieldThe dividend yield represents the value of our stock’s annualized dividend as compared to our interest, exclude regular maintenance and operational costs. See Note 10. Long-Term Debt.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, |
| (weighted averages) | | 2018 | | 2017 | | 2016 |
| Expected Term (in Years) | | 6.7 |
| | 6.4 |
| | 6.3 |
|
| Expected Volatility | | 33.4 | % | | 33.2 | % | | 32.4 | % |
| Risk-Free Rate | | 2.6 | % | | 2.2 | % | | 1.6 | % |
| Expected Dividend Yield | | 1.2 | % | | 0.9 | % | | 0.7 | % |
| Weighted Average Grant-Date Fair Value | | $ | 10.47 |
| | $ | 13.26 |
| | $ | 10.10 |
|
Stock option activity was as follows: |
| | | | | | | | | | | | | |
| | | Options | | Weighted Average Exercise Price | | Weighted Average Remaining Contractual Term | | Aggregate Intrinsic Value |
| | | | | (per share) | | (in years) | | (in millions) |
| Outstanding at December 31, 2017 | | 15,549,222 |
| | $ | 43.42 |
| | | | |
| Granted | | 551,888 |
| | 30.20 |
| | | | |
| Exercised | | (576,617 | ) | | 34.55 |
| | | | |
| Forfeited | | (1,672,473 | ) | | 40.04 |
| | | | |
| Outstanding at December 31, 2018 | | 13,852,020 |
| | $ | 44.04 |
| | 5.0 | | $ | — |
|
| Exercisable at December 31, 2018 | | 11,866,188 |
| | $ | 45.58 |
| | 4.0 | | $ | — |
|
|
| | |
| Noble Energy, Inc. | |
| Notes to Consolidated Financial Statements | |
The total intrinsic value of options exercised was $5 million in 2018, $4 million in 2017 and $10 million in 2016. As of December 31, 2018, $11 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, |
| | 2018 | | 2017 | | 2016 |
| Number of Simulations | 10,000,000 |
| | 500,000 |
| | 500,000 |
|
| Expected Volatility | 35 | % | | 35 | % | | 38 | % |
| Risk-Free Rate | 2.3 | % | | 1.5 | % | | 1.0 | % |
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 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, 2017 | | 610,159 |
| | $ | 31.65 |
| | 167,483 |
| | $ | 6.82 |
|
| Vested | | (83,276 | ) | | 31.65 |
| | — |
| | — |
|
| Forfeited | | (59,518 | ) | | 31.65 |
| | (17,187 | ) | | 6.82 |
|
| Outstanding at December 31, 2018 | | 467,365 |
| | $ | 31.65 |
| | 150,296 |
| | $ | 6.82 |
|
As of December 31, 2018, compensation cost related to phantom units remained to be recognized was de minimis. The remaining cost is expected to be recognized in first quarter 2019. The total fair value of phantom units that vested in 2018 was de minimis. Common stock dividends accrue on phantom units and are paid upon vesting.
Other Compensation Plans
401(k) PlanWe sponsor a 401(k) savings plan. All regular employees are eligible to participate. We make contributions to match employee contributions up to the first 6% of compensation deferred into the plan, and certain profit sharing contributions for employees hired on or after May 1, 2006, based upon their ages and salaries. We made cash contributions of $31 million in 2018, $31 million in 2017, and $32 million in 2016.
Deferred Compensation PlanWe have a non-qualified deferred compensation plan for which participant-directed investments are held in a rabbi trust and are available to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Participants in that nonqualified deferred compensation plan may elect to receive distributions in either cash or shares of our common stock. Components of that rabbi trust are as follows: |
| | | | | | | | |
| | | 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 |
|
Assets of that rabbi trust, other than our common stock, are invested in certain mutual funds that cover an investment spectrum ranging from equities to money market instruments. These mutual funds have published market prices and are reported at fair value. See Note 14. Fair Value Measurements and Disclosures. The mutual funds are included in the mutual fund investments account in other noncurrent assets in the consolidated balance sheets. Shares of our common stock held by the rabbi trust holding common stock are accounted for as treasury stock (recorded at cost, $16.72 per share) in the shareholders’ equity section of the consolidated balance sheets. Amounts payable to plan participants are included in other noncurrent liabilities in the consolidated balance sheets and include the market value of the shares of our common stock.
Approximately 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 2018, 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 $18 million in 2018, $21 million in 2017 and $22 million in 2016.
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 $2 million in 2018, $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 of $104 million and $116 million were outstanding at December 31, 2018 and 2017, respectively, under those other plans.
|
| | |
| Noble Energy, Inc. | |
| Supplemental Oil and Gas Information | |
| | (Unaudited) | |
In accordance with US GAAP for disclosures about oil and gas producing activities, and SEC rules for oil and gas reporting disclosures, we are making the following disclosures about our crude oil, NGL and natural gas reserves and exploration and production activities. In 2017 we established our Midstream business as a new reportable segment. The results of operations, costs incurred and capitalized costs associated with our Midstream reportable segment are not included in this disclosure. Prior period amounts are presented on a comparable basis.
Reserves There are numerous uncertainties inherent in estimating quantities of proved crude oil, NGL and natural gas reserves and reserves engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserves estimates are often different from the quantities of crude oil, NGL and natural gas that are ultimately recovered.
Economic producibility of reserves is dependent on the crude oil, NGL and natural gas prices used in the reserves estimate. We based our December 31, 2018, 2017, 2016, and 20152016 reserves estimates on 12-month average commodity prices, unless contractual arrangements designate the price to be used, in accordance with SEC rules. However, commodity prices are volatile and declines in crude oil, NGL and natural gas prices could result in negative reserves revisions. Production, development and abandonment costs are based on year-end economic conditions; therefore increases in these costs could also result in negative reserves revisions. Alternatively, decreases in these costs could result in positive reserves revisions.
DefinitionsThe following definitions apply to the terms used in the paragraphs above:
Reserves Estimate The determination of an estimate of a quantity of oil or gas reserves that are thought to exist at a certain date, considering existing prices and reservoir conditions.
Reserves Audit The process of reviewing certain of the pertinent facts interpreted and assumptions underlying a reserves estimate prepared by another party and the rendering of an opinion about the appropriateness of the methodologies employed, the adequacy and quality of the data relied upon, the depth and thoroughness of the reserves estimation process, the classification of reserves appropriate to the relevant definitions used, and the reasonableness of the estimated reserves quantities.
The following definitions apply to our categories of proved reserves:
Proved Oil and Gas Reserves Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to produce the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
Developed Oil and Gas Reserves Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared withto 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) |
| | | United States | | Equatorial Guinea | | Israel | | Total |
| Proved Reserves as of: | | | | | | | | |
| December 31, 2014 | | 236 |
| | 65 |
| | 3 |
| | 304 |
|
Revisions of Previous Estimates (1) | | (56 | ) | | (5 | ) | | — |
| | (61 | ) |
Extensions, Discoveries and Other Additions (2) | | 42 |
| | — |
| | — |
| | 42 |
|
Purchase of Minerals in Place (3) | | 65 |
| | — |
| | — |
| | 65 |
|
| Sale of Minerals in Place | | (2 | ) | | — |
| | — |
| | (2 | ) |
Production (5) | | (29 | ) | | (12 | ) | | — |
| | (41 | ) |
| December 31, 2015 | | 256 |
| | 48 |
| | 3 |
| | 307 |
|
Revisions of Previous Estimates (1) | | 14 |
| | (4 | ) | | — |
| | 10 |
|
Extensions, Discoveries and Other Additions (2) | | 66 |
| | — |
| | — |
| | 66 |
|
| Sale of Minerals in Place | | (4 | ) | | — |
| | — |
| | (4 | ) |
Production (5) | | (36 | ) | | (10 | ) | | — |
| | (46 | ) |
| December 31, 2016 | | 296 |
| | 34 |
| | 3 |
| | 333 |
|
Revisions of Previous Estimates (1) | | 29 |
| | 2 |
| | — |
| | 31 |
|
Extensions, Discoveries and Other Additions (2) | | 104 |
| | — |
| | 6 |
| | 110 |
|
Purchase of Minerals in Place (3) | | 43 |
| | — |
| | — |
| | 43 |
|
Sale of Minerals in Place (4) | | (12 | ) | | — |
| | — |
| | (12 | ) |
Production (5) | | (41 | ) | | (7 | ) | | — |
| | (48 | ) |
| December 31, 2017 | | 419 |
| | 29 |
| | 9 |
| | 457 |
|
| Proved Developed Reserves as of: | | |
| | |
| | |
| | |
|
| December 31, 2014 | | 119 |
| | 52 |
| | 3 |
| | 174 |
|
| December 31, 2015 | | 137 |
| | 34 |
| | 3 |
| | 174 |
|
| December 31, 2016 | | 138 |
| | 34 |
| | 3 |
| | 175 |
|
| December 31, 2017 | | 176 |
| | 29 |
| | 3 |
| | 208 |
|
| Proved Undeveloped Reserves as of: | | |
| | |
| | |
| | |
|
| December 31, 2014 | | 117 |
| | 13 |
| | — |
| | 130 |
|
| December 31, 2015 | | 119 |
| | 14 |
| | — |
| | 133 |
|
| December 31, 2016 | | 158 |
| | — |
| | — |
| | 158 |
|
| December 31, 2017 | | 243 |
| | — |
| | 6 |
| | 249 |
|
|
| | | | | | | | | | | | |
| | | Crude Oil and Condensate (MMBbls) |
| | | 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 | ) |
| December 31, 2016 | | 296 |
| | 34 |
| | 3 |
| | 333 |
|
| Revisions of Previous Estimates | | 29 |
| | 2 |
| | — |
| | 31 |
|
| Extensions, Discoveries and Other Additions | | 104 |
| | — |
| | 6 |
| | 110 |
|
| Purchase of Minerals in Place | | 43 |
| | — |
| | — |
| | 43 |
|
| Sale of Minerals in Place | | (12 | ) | | — |
| | — |
| | (12 | ) |
| Production | | (41 | ) | | (7 | ) | | — |
| | (48 | ) |
| December 31, 2017 | | 419 |
| | 29 |
| | 9 |
| | 457 |
|
| Revisions of Previous Estimates | | (31 | ) | | 3 |
| | — |
| | (28 | ) |
| Extensions, Discoveries and Other Additions | | 98 |
| | 3 |
| | — |
| | 101 |
|
| Sale of Minerals in Place | | (24 | ) | | — |
| | (1 | ) | | (25 | ) |
| Production | | (42 | ) | | (6 | ) | | — |
| | (48 | ) |
| December 31, 2018 | | 420 |
| | 29 |
| | 8 |
| | 457 |
|
| Proved Developed Reserves as of: | | |
| | |
| | |
| | |
|
| December 31, 2015 | | 137 |
| | 34 |
| | 3 |
| | 174 |
|
| December 31, 2016 | | 138 |
| | 34 |
| | 3 |
| | 175 |
|
| December 31, 2017 | | 176 |
| | 29 |
| | 3 |
| | 208 |
|
| December 31, 2018 | | 165 |
| | 26 |
| | 2 |
| | 193 |
|
| Proved Undeveloped Reserves as of: | | |
| | |
| | |
| | |
|
| December 31, 2015 | | 119 |
| | 14 |
| | — |
| | 133 |
|
| December 31, 2016 | | 158 |
| | — |
| | — |
| | 158 |
|
| December 31, 2017 | | 243 |
| | — |
| | 6 |
| | 249 |
|
| December 31, 2018 | | 255 |
| | 3 |
| | 6 |
| | 264 |
|
Revisions of Previous Estimates Oil revisions included:
Price Revisions
| |
(1)
◦ | The 2015 US revisions were primarily associated with negative2016 positive price revisions of 70included 19 MMBbls to our onshore programs due to a decline in the 12-month averageUS and 4 MMBbls in Equatorial Guinea. |
| |
| ◦ | 2017 positive price of crude oil; partially offset byrevisions 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 US revisions associated with positive performance and/or decreases in development or operating costs included revisions of 33 MMBbls in the DJ Basin, Marcellus Shale, Delaware Basin and Gulf of Mexico. |
| |
| ◦ | 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 performanceperformance. |
| |
| ◦ | 2018 includes negative non-price revisions of 42 MMBbls, which primarily includes 30 MMBbls for changes in expected recoveries and optimized lateral lengthsincreased operating and capital costs in the Delaware Basin, and 11 MMBbls for changes in the previously adopted development plan in the Eagle Ford Shale. Equatorial Guinea revisions were associated with negative price revisions.Shale and DJ Basin. |
The 2016 US revisions associated with positive performance and/or decreases in development or operating costs included revisions of 33 MMBbls in the DJ Basin, Marcellus Shale, Delaware Basin and Gulf of Mexico; partially offset by negative revisions of 19 MMBbls due to lower commodity prices. Equatorial Guinea revisions were primarily due to lower commodity prices.
The 2017 US revisions associated with positive performance totaled 17 MMBbls, of which 14 were primarily attributable to the Delaware Basin due to continued optimization of well development and improved producing well performance. Revisions also included positive price revisions of 12 MMBbls.
|
| | |
| The 2015 increase in US reserves was attributableNoble Energy, Inc. | |
| Supplemental Oil and Gas Information | |
| (Unaudited) | |
The
Extensions, Discoveries and Other Additions Oil extensions, discoveries and other additions included:
2016 increaseextensions in US reserves included 38 MMBbls in the DJ Basin and 28 MMBbls in the Delaware Basin and Eagle Ford Shale, and was associated with increased performance from our horizontal drilling programs.
The 2017 increaseextensions in US reserves included additions of 59 MMBbls in the Delaware Basin, 42 MMBbls in the DJ Basin and 3 MMBbls in the Eagle Ford Shale primarily due to the addition of planned new locations and activity.
| |
(3)
| The 2015 increase was attributable to reserves acquired in the Rosetta Merger. |
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 oil was attributable to the reserves acquired in the Clayton Williams Energy Acquisition.
Sale of Minerals in Place Sales of oil minerals in place included:
2017 includes the sale of 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) | |
The 2017 increase was attributable to the reserves acquired in the Clayton Williams Energy Acquisition.
| |
(4)
| In 2017, we sold the Marcellus Shale upstream assets and other non-strategic US onshore assets. |
| |
(5)
| Equatorial Guinea production included sales from Alba Plant of approximately 1 MMBbl in 2017 and 3 MMBbl in each of the years 2016 and 2015. |
|
| | |
| 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 (MMBbls) |
| | | United States | | Equatorial Guinea | | Total | | United States | | Equatorial Guinea | | Total |
| Proved Reserves as of: | | | | | | | | | | | | |
| December 31, 2014 | | 113 |
| | 15 |
| | 128 |
| |
Revisions of Previous Estimates (1) | | (37 | ) | | — |
| | (37 | ) | |
Extensions, Discoveries and Other Additions (2) | | 15 |
| | — |
| | 15 |
| |
Purchase of Minerals in Place (3) | | 100 |
| | — |
| | 100 |
| |
| Sale of Minerals in Place | | (1 | ) | | — |
| | (1 | ) | |
Production (4) | | (14 | ) | | (2 | ) | | (16 | ) | |
| December 31, 2015 | | 176 |
| | 13 |
| | 189 |
| | 176 |
| | 13 |
| | 189 |
|
Revisions of Previous Estimates (1) | | 16 |
| | 1 |
| | 17 |
| |
Extensions, Discoveries and Other Additions (2) | | 31 |
| | — |
| | 31 |
| |
| 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 | ) |
| December 31, 2016 | | | 207 |
| | 12 |
| | 219 |
|
| Revisions of Previous Estimates | | | 31 |
| | 1 |
| | 32 |
|
| Extensions, Discoveries and Other Additions | | | 32 |
| | — |
| | 32 |
|
| Purchase of Minerals in Place | | 4 |
| | — |
| | 4 |
| | 7 |
| | — |
| | 7 |
|
| Sale of Minerals in Place | | — |
| | — |
| | — |
| | (38 | ) | | — |
| | (38 | ) |
Production (4) | | (20 | ) | | (2 | ) | | (22 | ) | |
| December 31, 2016 | | 207 |
| | 12 |
| | 219 |
| |
Revisions of Previous Estimates (1) | | 31 |
| | 1 |
| | 32 |
| |
Extensions, Discoveries and Other Additions (2) | | 32 |
| | — |
| | 32 |
| |
Purchase of Minerals in Place (3) | | 7 |
| | — |
| | 7 |
| |
Sale of Minerals in Place (5) | | (38 | ) | | — |
| | (38 | ) | |
Production (4) | | (21 | ) | | (2 | ) | | (23 | ) | |
| Production | | | (21 | ) | | (2 | ) | | (23 | ) |
| December 31, 2017 | | 218 |
| | 11 |
| | 229 |
| | 218 |
| | 11 |
| | 229 |
|
| Revisions of Previous Estimates | | | 21 |
| | — |
| | 21 |
|
| Extensions, Discoveries and Other Additions | | | 48 |
| | — |
| | 48 |
|
| Sale of Minerals in Place | | | (7 | ) | | — |
| | (7 | ) |
| Production | | | (23 | ) | | (2 | ) | | (25 | ) |
| December 31, 2018 | | | 257 |
| | 9 |
| | 266 |
|
| Proved Developed Reserves as of: | | |
| | |
| | | | |
| | |
| | |
| December 31, 2014 | | 64 |
| | 8 |
| | 72 |
| |
| December 31, 2015 | | 101 |
| | 5 |
| | 106 |
| | 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 |
|
| Proved Undeveloped Reserves as of: | | | | | | | | | | | | |
| December 31, 2014 | | 49 |
| | 7 |
| | 56 |
| |
| December 31, 2015 | | 75 |
| | 8 |
| | 83 |
| | 75 |
| | 8 |
| | 83 |
|
| December 31, 2016 | | 94 |
| | — |
| | 94 |
| | 94 |
| | — |
| | 94 |
|
| December 31, 2017 | | 99 |
| | — |
| | 99 |
| | 99 |
| | — |
| | 99 |
|
| December 31, 2018 | | | 136 |
| | — |
| | 136 |
|
Revisions of Previous Estimates NGL revisions included:
Price Revisions
| |
(1)
◦ | The 20152016 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 negative price revisions of 44 MMBbls related to our onshore programs due to a decline in the 12-month average price; partially offset by a positive revision from our Marcellus Shale program due to positive well performance. |
The 2016 US revisions were primarily associated with positive performance revisions of 11 MMBbls in the Marcellus Shale and 9 MMBbls in the DJ Basin; partially offset by negative commodity price revisions of 4 MMBbls.
The 2017 US revisions associated with positive performance revisions totaled 25 MMBbls, including 11 MMBbls in the Delaware Basin, 8 MMBbls in the Eagle Ford Shale and 6 MMBbls in the DJ Basin, due to continued optimization of well development and improved producing well performance. Revisions also included positive price revisions of 6 MMBbls.
| |
(2)
| The 2015 additions included 14 MMBbls due to positive producing well performance and optimized lateral lengths in the DJ Basin. |
| |
| ◦ | 2017 US revisions associated with positive performance revisions totaled 25 MMBbls, including 11 MMBbls in the Delaware Basin, 8 MMBbls in the Eagle Ford Shale and 6 MMBbls in the DJ Basin, due to continued optimization of well development and improved producing well performance. |
| |
| ◦ | 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. |
The
|
| | |
| Noble Energy, Inc. | |
| Supplemental Oil and Gas Information | |
| (Unaudited) | |
Extensions, Discoveries and Other Additions NGL extensions, discoveries and other additions included:
2016 additionsextensions in US reserves primarily included an increase of 15 MMBbls in the DJ Basin and 14 MMBbls in the Delaware Basin and Eagle Ford shale due to improved well performance and/or decreases in development or operating costs.
The 2017 additionsextensions in US reserves included 19 MMBbls in the DJ Basin, 9 MMBbls in the Delaware Basin and 4 MMBbls in the Eagle Ford Shale primarily due to the addition of planned new locations and activity.
(3) The 2015 increase was attributable to reserves acquired in the Rosetta Merger.
The 2017 increase was attributable2018 extensions relate to the reserves acquiredaddition of planned new locations and activity, of which 25 MMBbls, 15 MMBbls and 8 MMBbls relate to the DJ Basin, Delaware Basin and Eagle Ford Shale, respectively.
Sale of Minerals in Place Sales of NGL minerals in place included:
2017 sales included the Clayton Williams Energy Acquisition.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) | |
(4) Equatorial Guinea production represented sales from the Alba Plant.
(5) In 2017, we sold the Marcellus Shale upstream assets and other non-strategic US onshore assets.
|
| | |
| 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 and Casinghead Gas (Bcf) |
| | | United States | | Israel (1) | | Equatorial Guinea | | Total | | United States | | Israel | | Equatorial Guinea | | Total |
| Proved Reserves as of: | | | | | | | | | | | | | | | | |
| December 31, 2014 | | 2,804 |
| | 2,416 |
| | 613 |
| | 5,833 |
| |
Revisions of Previous Estimates (2) | | (705 | ) | | (20 | ) | | 4 |
| | (721 | ) | |
Extensions, Discoveries and Other Additions (3) | | 257 |
| | — |
| | — |
| | 257 |
| |
Purchase of Minerals in Place (4) | | 629 |
| | — |
| | — |
| | 629 |
| |
| 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 | | (16 | ) | | — |
| | — |
| | (16 | ) | | (224 | ) | | (214 | ) | | — |
| | (438 | ) |
| Production | | (258 | ) | | (92 | ) | | (83 | ) | | (433 | ) | | (322 | ) | | (103 | ) | | (86 | ) | | (511 | ) |
| December 31, 2015 | | 2,711 |
| | 2,304 |
| | 534 |
| | 5,549 |
| |
Revisions of Previous Estimates (2) | | 181 |
| | (3 | ) | | 38 |
| | 216 |
| |
Extensions, Discoveries and Other Additions (3) | | 492 |
| | — |
| | — |
| | 492 |
| |
| December 31, 2016 | | | 2,838 |
| | 1,984 |
| | 486 |
| | 5,308 |
|
| Revisions of Previous Estimates | | | 124 |
| | 292 |
| | 13 |
| | 429 |
|
| Extensions, Discoveries and Other Additions | | | 299 |
| | 3,271 |
| | — |
| | 3,570 |
|
| Purchase of Minerals in Place | | — |
| | — |
| | — |
| | — |
| | 46 |
| | — |
| | — |
| | 46 |
|
Sale of Minerals in Place (5) | | (224 | ) | | (214 | ) | | — |
| | (438 | ) | |
| Production | | (322 | ) | | (103 | ) | | (86 | ) | | (511 | ) | |
| December 31, 2016 | | 2,838 |
| | 1,984 |
| | 486 |
| | 5,308 |
| |
Revisions of Previous Estimates (2) | | 124 |
| | 292 |
| | 13 |
| | 429 |
| |
Extensions, Discoveries and Other Additions (3) | | 299 |
| | 3,271 |
| | — |
| | 3,570 |
| |
Purchase of Minerals in Place (4) | | 46 |
| | — |
| | — |
| | 46 |
| |
Sale of Minerals in Place (5) | | (1,264 | ) | | — |
| | (1 | ) | | (1,265 | ) | |
| Sale of Minerals in Place | | | (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 |
|
| Extensions, Discoveries and Other Additions | | | 373 |
| | 68 |
| | 2 |
| | 443 |
|
| Sale of Minerals in Place | | | (79 | ) | | (502 | ) | | — |
| | (581 | ) |
| Production | | | (172 | ) | | (86 | ) | | (78 | ) | | (336 | ) |
| December 31, 2018 | | | 1,944 |
| | 4,930 |
| | 357 |
| | 7,231 |
|
| Proved Developed Reserves as of: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| December 31, 2014 | | 1,459 |
| | 1,973 |
| | 377 |
| | 3,809 |
| |
| December 31, 2015 | | 1,813 |
| | 1,879 |
| | 247 |
| | 3,939 |
| | 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 |
|
| Proved Undeveloped Reserves as of: | | | | | | | | | | | | | | | | |
| December 31, 2014 | | 1,345 |
| | 443 |
| | 236 |
| | 2,024 |
| |
| December 31, 2015 | | 898 |
| | 425 |
| | 287 |
| | 1,610 |
| | 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 |
|
Revisions of Previous Estimates Gas revisions included:
Price Revisions
| |
(1)
◦ | In accordance with the terms2016 included negative commodity price revisions of the Framework, we are required to reduce our ownership81 Bcf in the TamarUS and Dalit fields from 36% to 25% by year-end 2021.During 2016, we reduced our ownership to 32.5% through the sale of a 3.5% interest. At December 31, 2017, an additional 7.5% interest is included20 Bcf in assets held for sale. Proved reserves associated with the interest currently held for sale total approximately 502 Bcf, including 89 Bcf of PUDs, at December 31, 2017 and are included in the table above. In January 2018, we entered into an agreement to divest the 7.5% interest. See Note 4. Acquisitions, Divestitures and Merger. |
| |
(2)
◦ | The 20152017 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 negative price revisions of 1.1 Tcf to our onshore programs due to a declinepositive performance and/or decreases in development or operating costs and included 167 Bcf in the 12-month average price, offset by a positive revision primarily to our Marcellus Shale program due to positive well performance.and 95 Bcf in the DJ Basin. Equatorial Guinea revisions were associated with positive performance revisions toof 58 Bcf at the Alba field. Israel |
| |
| ◦ | 2017 performance revisions wereof 66 Bcf primarily associated withincluded 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 Mari-B field.DJ Basin primarily associated vertical well locations. |
The 2016 US revisions were primarily associated with positive performance and/or decreases in development or operating costs and included 167 Bcf in the Marcellus Shale and 95 Bcf in the DJ Basin, partially offset by negative commodity price revisions of 81 Bcf. Equatorial Guinea revisions were associated with positive performance revisions of 58 Bcf at the Alba field, partially offset by negative commodity price revisions of 20 Bcf.
The 2017 US revisions were associated primarily with positive well performance and an increase in commodity prices. Net performance revisions of 66 Bcf primarily included 81 Bcf in the Eagle Ford Shale and 31 Bcf in the Delaware Basin, partially offset by negative performance revisions of 49 Bcf in the DJ Basin primarily associated vertical well locations. The 2017 Israel performance revisions of
|
| | |
| Noble Energy, Inc. | |
| Supplemental Oil and Gas Information | |
| | (Unaudited) | |
292 Bcf were associated with the integration of the Tamar 8 well results into our geologic modeling across the reservoir. Positive price revisions were approximately 71 Bcf.
| |
(3)
◦ | The 2015 increase2018 net negative revisions of 24 Bcf include negative performance revisions of 43 Bcf in the US, reserves included an increasepartially offset by positive revisions of 17619 Bcf in Equatorial Guinea and Israel. US includes positive revisions of 70 Bcf in the DJ Basin and 81 Bcf from Marcellus Shale developmentprimarily due to positive producing well performanceASC 606 adoption, offset by negative revisions of 71 Bcf in the Eagle Ford Shale due to changes in the previously adopted development plan and optimized lateral lengths.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. |
The Extensions, Discoveries and Other Additions Gas extensions, discoveries and other additions included:
2016 increaseextensions in US reserves included positive performance revisions associated with our horizontal drilling programs including 230 Bcf in the Marcellus Shale, 185 Bcf in the DJ Basin, and 77 Bcf in the Delaware Basin and Eagle Ford Shale.
The 2017 increaseextensions in US reserves included additions of 224 Bcf in the DJ Basin, 53 Bcf in the Delaware Basin and 22 Bcf in the Eagle Ford Shale primarily due to the addition of planned new locations and activity. The 2017 increase in Israel reserves represented sanction of the first phase of development of the Leviathan natural gas project.
| |
(4)
| The 2015 increase was attributable to reserves acquired2018 extensions in reserves relate to drilling plans for new wells. Increases in the US include 254 Bcf, 77 Bcf and 42 Bcf in the DJ Basin, Delaware Basin and Eagle Ford Shale, respectively, and the Rosetta Merger. |
The 2017 increase was attributablein Israel of 68 Bcf relates to the reserves acquiredTamar field.
Sale of Minerals in Place Sales of gas minerals in place included:
2016 included the sale of non-strategic US onshore assets, an acreage exchange in the Clayton Williams Energy Acquisition.
| |
(5)
| In 2016, we sold US onshore assets in the DJ Basin and Eagle Ford Shale. We also executed an acreage exchange in the Marcellus Shale where we relinquished 185 Bcf, and we reduced our ownership in the Tamar field, offshore Israel. |
In 2017, we sold a 3.5% ownership interest in the Tamar field, offshore Israel.
2017 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 and natural gas producing activities within the E&P reporting segments are as follows: | | | | | United States | | Israel | | Equatorial Guinea | | Other Int'l | | Total | | | | | | | | | | | |
(millions) | | | | | | | | | | | | United States | | Israel | | Equatorial Guinea | | Other Int'l | | Total |
| Year Ended December 31, 2018 | | | |
| | |
| | |
| | |
| | |
|
| Revenues | | | $ | 3,590 |
| | $ | 480 |
| | $ | 543 |
| | $ | — |
| | $ | 4,613 |
|
Production Costs (1) | | | 1,276 |
| | 37 |
| | 110 |
| | 2 |
| | 1,425 |
|
| Exploration Expense | | | 48 |
| | 2 |
| | 1 |
| | 78 |
| | 129 |
|
| DD&A | | | 1,642 |
| | 60 |
| | 115 |
| | 2 |
| | 1,819 |
|
Loss (Gain) on Divestitures, Net (2) | | | 36 |
| | (376 | ) | | — |
| | — |
| | (340 | ) |
Asset Impairments (3) | | | 169 |
| | — |
| | — |
| | — |
| | 169 |
|
| Marketing Expense | | | 40 |
| | — |
| | — |
| | — |
| | 40 |
|
| Gain on Asset Retirement Obligation Revisions | | | — |
| | (8 | ) | | — |
| | (17 | ) | | (25 | ) |
| Income (Loss) before Income Taxes | | | 379 |
| | 765 |
| | 317 |
| | (65 | ) | | 1,396 |
|
Income Tax Expense (4) | | | 80 |
| | 176 |
| | 79 |
| | — |
| | 335 |
|
Results of Operations (5) | | | $ | 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 |
| | 1,739 |
| | 76 |
| | 146 |
| | 4 |
| | 1,965 |
|
Loss on Marcellus Shale Upstream Divestiture (2) | | 2,379 |
| | — |
| | — |
| | — |
| | 2,379 |
| |
Loss on Marcellus Shale Upstream Divestiture and Other (6) | | | 2,286 |
| | — |
| | — |
| | — |
| | 2,286 |
|
Asset Impairments (3) | | 63 |
| | — |
| | — |
| | 7 |
| | 70 |
| | 63 |
| | — |
| | — |
| | 7 |
| | 70 |
|
| Marketing Expense | | | 47 |
| | — |
| | — |
| | — |
| | 47 |
|
| Gain on Asset Retirement Obligation Revisions | | | — |
| | — |
| | — |
| | (42 | ) | | (42 | ) |
| (Loss) Income before Income Taxes | | (2,326 | ) | | 409 |
| | 120 |
| | (98 | ) | | (1,895 | ) | | (2,280 | ) | | 409 |
| | 120 |
| | (56 | ) | | (1,807 | ) |
Income Tax Expense (Benefit) (4) | | (814 | ) | | 98 |
| | 30 |
| | — |
| | (686 | ) | |
Income Tax (Benefit) Expense (4) | | | (798 | ) | | 98 |
| | 30 |
| | — |
| | (670 | ) |
Results of Operations (5) | | $ | (1,512 | ) | | $ | 311 |
| | $ | 90 |
| | $ | (98 | ) | | $ | (1,209 | ) | | $ | (1,482 | ) | | $ | 311 |
| | $ | 90 |
| | $ | (56 | ) | | $ | (1,137 | ) |
| Year Ended December 31, 2016 | | | | | | | | | | | | | | | | | | | | |
| Revenues | | $ | 2,416 |
| | $ | 540 |
| | $ | 433 |
| | $ | — |
| | $ | 3,389 |
| | $ | 2,416 |
| | $ | 540 |
| | $ | 433 |
| | $ | — |
| | $ | 3,389 |
|
Production Costs (1) | | 1,108 |
| | 49 |
| | 118 |
| | 1 |
| | 1,276 |
| | 1,108 |
| | 49 |
| | 118 |
| | 1 |
| | 1,276 |
|
Exploration Expense (6) | | 245 |
| | 26 |
| | 469 |
| | 185 |
| | 925 |
| |
| DD&A | | 2,103 |
| | 81 |
| | 205 |
| | 6 |
| | 2,395 |
| |
Asset Impairments (4) | | — |
| | 88 |
| | — |
| | 4 |
| | 92 |
| |
| (Loss) Income before Income Taxes | | (1,040 | ) | | 296 |
| | (359 | ) | | (196 | ) | | (1,299 | ) | |
Income Tax Expense (Benefit) (4) | | (364 | ) | | 74 |
| | (90 | ) | | — |
| | (380 | ) | |
Results of Operations (5) | | $ | (676 | ) | | $ | 222 |
| | $ | (269 | ) | | $ | (196 | ) | | $ | (919 | ) | |
| Year Ended December 31, 2015 | | | | | | | | | | | |
| Revenues | | $ | 2,011 |
| | $ | 497 |
| | $ | 580 |
| | $ | 5 |
| | $ | 3,093 |
| |
Production Costs (1) | | 916 |
| | 60 |
| | 145 |
| | 6 |
| | 1,127 |
| |
| Exploration Expense | | 202 |
| | 6 |
| | 1 |
| | 279 |
| | 488 |
| |
Exploration Expense (7) | | | 245 |
| | 26 |
| | 469 |
| | 185 |
| | 925 |
|
| DD&A | | 1,677 |
| | 70 |
| | 326 |
| | — |
| | 2,073 |
| | 2,103 |
| | 81 |
| | 205 |
| | 6 |
| | 2,395 |
|
Asset Impairments (3) | | 158 |
| | 36 |
| | 339 |
| | — |
| | 533 |
| | — |
| | 88 |
| | — |
| | 4 |
| | 92 |
|
| Income (Loss) before Income Taxes | | (942 | ) | | 325 |
| | (231 | ) | | (280 | ) | | (1,128 | ) | |
Income Tax Expense (4) | | (330 | ) | | 86 |
| | (58 | ) | | (5 | ) | | (307 | ) | |
| (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) | | $ | (612 | ) | | $ | 239 |
| | $ | (173 | ) | | $ | (275 | ) | | $ | (821 | ) | | $ | (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. |
| |
(3) | 20172018 asset impairments relate primarily to the sale of our Gulf of Mexico Troubadour well.assets. |
2017 asset impairments relate primarily to the Gulf of Mexico Troubadour well.
2016 asset impairments relate to certain Leviathan development concept costs.
2015 asset impairments related to reductions in the forward crude oil prices as of December 31, 2015 and revisions in expected field abandonment and other costs for offshore properties.
See Note 5. Asset Impairments. | |
(4) | Income tax expense is based upon respective corporate statutory tax rates. During 2018, 2017, 2016, and 2015,2016, we incurred exploration expense in currently non-commercial other international locations; therefore, no tax benefit was included in income tax expense associated with other international as we could not conclude it was more likely than not that some portion or all of the deferred tax assets would be realized. |
| |
(5) | Results of operations exclude the mark-to-market gain or loss on commodity derivative instruments, corporate activities and overhead and interest costs. See Note 8.13. Derivative Instruments and Hedging Activities. |
|
| | |
| 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. |
| |
(6)(7)
| Equatorial Guinea exploration expense includes amounts related to the write off of costs associated with certain discoveries. See Note 6.7. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs. |
|
| | |
| Noble Energy, Inc. | |
| Supplemental Oil and Gas Information | |
| (Unaudited) | |
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities (Unaudited)
Costs incurred include both capitalized costs and costs charged to expense when incurred for oil and gas property acquisition, exploration, and development activities associated with the E&P reporting segments. Costs incurred also include new AROs established in the current year, as well as changes to AROs resulting from changes to cost estimates during the year. Exploration costs presented below include the costs of drilling and equipping successful and unsuccessful exploration wells during the year, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells. Costs associated with activities of our Midstream businesssegment and other corporate activities are not included. |
| | | | | | | | | | | | | | | | | | | | |
| (millions) | | United States | | Israel | | Equatorial Guinea | | Other Int'l (1) | | Total |
| 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) | | $ | 839 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 839 |
|
Unproved (2) | | 1,817 |
| | — |
| | — |
| | — |
| | 1,817 |
|
Exploration Costs (3) | | 59 |
| | 6 |
| | 4 |
| | 90 |
| | 159 |
|
Development Costs (4) | | 1,870 |
| | 483 |
| | 33 |
| | (39 | ) | | 2,347 |
|
| Total Consolidated Operations | | $ | 4,585 |
| | $ | 489 |
| | $ | 37 |
| | $ | 51 |
| | $ | 5,162 |
|
| December 31, 2016 | | |
| | |
| | |
| | |
| | |
|
| 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 |
|
| Total Consolidated Operations | | $ | 1,403 |
| | $ | 135 |
| | $ | 56 |
| | $ | 44 |
| | $ | 1,638 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| | | United States | | Israel | | Equatorial Guinea | | Other Int'l (1) | | Total |
| (millions) | | | | | | | | | | |
| December 31, 2017 | | | | | | | | | | |
| Property Acquisition Costs | | | | | | | | | | |
Proved (2) | | $ | 839 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 839 |
|
Unproved (2) | | 1,817 |
| | — |
| | — |
| | — |
| | 1,817 |
|
Exploration Costs (3) | | 59 |
| | 6 |
| | 4 |
| | 90 |
| | 159 |
|
Development Costs (4) | | 1,870 |
| | 483 |
| | 33 |
| | (39 | ) | | 2,347 |
|
| Total Consolidated Operations | | $ | 4,585 |
| | $ | 489 |
| | $ | 37 |
| | $ | 51 |
| | $ | 5,162 |
|
| December 31, 2016 | | |
| | |
| | |
| | |
| | |
|
| Property Acquisition Costs | | |
| | |
| | |
| | |
| | |
|
Proved (2) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Unproved (2) | | 234 |
| | — |
| | — |
| | — |
| | 234 |
|
Exploration Costs (4) | | 264 |
| | 26 |
| | 25 |
| | 44 |
| | 359 |
|
Development Costs (4) | | 905 |
| | 109 |
| | 31 |
| | — |
| | 1,045 |
|
| Total Consolidated Operations | | $ | 1,403 |
| | $ | 135 |
| | $ | 56 |
| | $ | 44 |
| | $ | 1,638 |
|
| December 31, 2015 | | |
| | |
| | |
| | |
| | |
|
| Property Acquisition Costs | | |
| | |
| | |
| | |
| | |
|
Proved (2) | | $ | 1,613 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1,613 |
|
Unproved (2) | | 1,478 |
| | — |
| | — |
| | 2 |
| | 1,480 |
|
Exploration Costs (3) | | 206 |
| | 22 |
| | 22 |
| | 234 |
| | 484 |
|
Development Costs (4) | | 2,111 |
| | 104 |
| | 75 |
| | 10 |
| | 2,300 |
|
| Total Consolidated Operations | | $ | 5,408 |
| | $ | 126 |
| | $ | 97 |
| | $ | 246 |
| | $ | 5,877 |
|
| |
(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. |
| |
(2) | 2017 proved and2018 unproved property acquisition costs include amounts allocated fromUS onshore undeveloped leasehold activity during the Clayton Williams Energy Acquisition (See Note 3. Clayton Williams Energy Acquisition) and the Delaware Basin Acquisition (See Note 4. Acquisitions, Divestitures and Merger). |
2017 proved and unproved property acquisition costs 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 4.5. Acquisitions Divestitures and MergerDivestitures. 2015 proved and unproved property acquisition costs include amounts allocated from the Rosetta Merger. See Note 4. Acquisitions, Divestitures and Merger. | |
(3) | 20172018 exploration costs includerelate primarily capitalized interest on Gulf of Mexico projects, and $7 million dry hole cost related to the Araku-1 exploration well, offshore Suriname. The remainder relates to seismic expense, drilling costs, and drilling costs.lease rentals. |
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 to seismic expense and drilling costs.
2016 exploration costs include $44 million drilling and completion of $44 million in the Gulf of Mexico.
2015 exploration costs include drilling and completion of $22 million in the Gulf of Mexico.
| |
(4) | Worldwide development costs include amounts spent to develop PUDs of approximately $1.0 billion in 2018, $1.2 billion in 2017, and $656 million in 2016,2016. |
|
| | |
| Noble Energy, Inc. | |
| Supplemental Oil and $1.5 billion in 2015.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 in 2017. Amounts incurred inwell.
Israel development costs for 2016 and 2015 relatedrelate 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 primarilyare 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 and 2015.
|
| | |
| Noble Energy, Inc. | |
| Supplemental Oil and Gas Information | |
| (Unaudited) | |
US2016. 2017 development costs include a decrease of $17 millionan increase in asset retirement obligations due to downward revisions and increases of $20 million in 2016 and $194 million in 2015.
Israel development costs include increases in asset retirement obligations of $4 million in 2017 and $46 million in 2015.
Equatorial Guinea development costs include increases (decreases) in asset retirement obligationsARO of $14 million in 2017 and $(10) million in 2015.million.
Other International development costs include increases (decreases)decreases in asset retirement obligationsARO of $(40)$40 million in 2017 mainlyprimarily associated with the North Sea abandonment project and $2 million in 2015.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, | | | | | |
| | | 2017 | | 2016 | | December 31, |
| (millions) | | | | | | 2018 | | 2017 |
Unproved Oil and Gas Properties (1) | | $ | 2,978 |
| | $ | 2,197 |
| | $ | 2,321 |
| | $ | 2,978 |
|
Proved Oil and Gas Properties (2) | | 26,111 |
| | 27,530 |
| | 24,955 |
| | 26,111 |
|
| Total Oil and Gas Properties | | 29,089 |
| | 29,727 |
| | 27,276 |
| | 29,089 |
|
| Accumulated DD&A | | (12,538 | ) | | (12,265 | ) | | (10,867 | ) | | (12,538 | ) |
| Net Capitalized Costs | | $ | 16,551 |
| | $ | 17,462 |
| | $ | 16,409 |
| | $ | 16,551 |
|
| |
(1) | Unproved oil and gas property costcosts at December 31, 20172018 include previous acquisition costs of $1.6$2.2 billion related to the Clayton Williams Energy Acquisition,Delaware Basin properties and $1.1 billion and $149$100 million related to the Delaware Basin and Eagle Ford Shale properties. |
Unproved oil and gas property costcosts at December 31, 20162017 include previous acquisition costs of $1.2$2.7 billion related to the Eagle Ford Shale and Delaware Basin properties and $758$149 million related to MarcellusEagle Ford Shale properties.
| |
(2) | Proved oil and gas properties at December 31, 20172018 include asset retirement costs of $941$966 million and assets held for sale of $448$133 million. |
Proved oil and gas properties at December 31, 20162017 include asset retirement costs of $884$941 million and $18 million of assets held for sale.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. | | | | | United States | | Israel (1) | | Equatorial Guinea | | Other Int'l (2) | | Total | | | | | | | | | | | |
| (millions) | | | | | | | | | | | | United States | | Israel (1) | | Equatorial Guinea | | Other Int'l (2) | | Total |
| December 31, 2018 | | | | | | | | | | | |
Future Cash Inflows (3) | | | $ | 38,542 |
| | $ | 27,559 |
| | $ | 2,528 |
| | $ | — |
| | $ | 68,629 |
|
Future Production Costs (4) | | | (14,793 | ) | | (2,478 | ) | | (1,180 | ) | | — |
| | (18,451 | ) |
Future Development Costs (5) | | | (5,793 | ) | | (1,038 | ) | | (170 | ) | | (32 | ) | | (7,033 | ) |
Future Income Tax Expense (6) | | | (2,061 | ) | | (12,185 | ) | | (277 | ) | | — |
| | (14,523 | ) |
| Future Net Cash Flows | | | 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 | ) |
| Standardized Measure of Discounted Future Net Cash Flows | | | $ | 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 (6) | | (948 | ) | | (13,088 | ) | | (216 | ) | | — |
| | (14,252 | ) | |
| Future Income Tax Expense | | | (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 |
| | $ | 19,924 |
| | $ | 10,159 |
| | $ | 1,851 |
| | $ | — |
| | $ | 31,934 |
|
Future Production Costs (4) | | (8,756 | ) | | (764 | ) | | (1,001 | ) | | — |
| | (10,521 | ) | | (8,756 | ) | | (764 | ) | | (1,001 | ) | | — |
| | (10,521 | ) |
Future Development Costs (5) | | (4,813 | ) | | (725 | ) | | (83 | ) | | (100 | ) | | (5,721 | ) | | (4,813 | ) | | (725 | ) | | (83 | ) | | (100 | ) | | (5,721 | ) |
| Future Income Tax Expense | | (941 | ) | | (4,228 | ) | | (141 | ) | | — |
| | (5,310 | ) | | (941 | ) | | (4,228 | ) | | (141 | ) | | — |
| | (5,310 | ) |
| Future Net Cash Flows | | 5,414 |
| | 4,442 |
| | 626 |
| | (100 | ) | | 10,382 |
| | 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 | ) | | (2,308 | ) | | (2,329 | ) | | (84 | ) | | 25 |
| | (4,696 | ) |
| Standardized Measure of Discounted Future Net Cash Flows | | $ | 3,106 |
| | $ | 2,113 |
| | $ | 542 |
| | $ | (75 | ) | | $ | 5,686 |
| | $ | 3,106 |
| | $ | 2,113 |
| | $ | 542 |
| | $ | (75 | ) | | $ | 5,686 |
|
| December 31, 2015 | | | | | | | | | | | |
Future Cash Inflows (3) | | $ | 19,099 |
| | $ | 11,835 |
| | $ | 2,965 |
| | $ | — |
| | $ | 33,899 |
| |
Future Production Costs (4) | | (8,728 | ) | | (1,128 | ) | | (1,351 | ) | | — |
| | (11,207 | ) | |
Future Development Costs (5) | | (4,092 | ) | | (682 | ) | | (101 | ) | | (100 | ) | | (4,975 | ) | |
| Future Income Tax Expense | | (837 | ) | | (5,281 | ) | | (189 | ) | | — |
| | (6,307 | ) | |
| Future Net Cash Flows | | 5,442 |
| | 4,744 |
| | 1,324 |
| | (100 | ) | | 11,410 |
| |
| 10% Annual Discount for Estimated Timing of Cash Flows | | (2,100 | ) | | (2,452 | ) | | (262 | ) | | 32 |
| | (4,782 | ) | |
| Standardized Measure of Discounted Future Net Cash Flows | | $ | 3,342 |
| | $ | 2,292 |
| | $ | 1,062 |
| | $ | (68 | ) | | $ | 6,628 |
| |
| |
(1) | In accordance with the Framework, we arewere required to reduce our ownership in the Tamar and Dalit fields from 36% to 25% by year-end 2021.During 2016, we reduced our ownership to 32.5% through the sale of a 3.5% interest. During 2018, we reduced our ownership to 25% through the sale of a 7.5% interest. Therefore, amounts at December 31, 2018 reflect a 25% interest while amounts at December 31, 2017 and 2016 reflect a 32.5% working interest, while 2015 amounts reflect a 36% working interest. At December 31, 2017, 7.5% of our 32.5% interest is included in assets held for sale. The portion of the standardized measure of discounted future net cash flows included in the table above,See Note 5. Acquisitions and associated with the interest currently held for sale, totals approximately $650 million at December 31, 2017. See Note 4. Acquisitions, Divestitures and Merger. The 2017 increase in the standardized measure of discounted future net cash inflows relates primarily to the sanction of the first phase of development of the Leviathan field. |
| |
(2) | Other International represents North Sea abandonment costs. |
| |
(3) | The standardized measure of discounted future net cash flows does not include cash flows relating to anticipated future methanol sales. |
| |
(4) | Production costs include lease operating expense, production and ad valorem taxes, transportation expense and general and administrative expense supporting crude oil and natural gas operations. |
| |
(5) | Future development costs include future abandonment costs for each location. See Note 9.8. 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 2016 and 2015,2016, future 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-end quantities of proved reserves, except in those instances where fixed and determinable price changes are provided by contractual arrangements at year-end. The discounted future cash flow estimates do not include the effects of derivative instruments. Average prices per region are as follows: | | | | | United States | | Israel | | Equatorial Guinea | | Total | | United States | | Israel | | Equatorial Guinea | | Total |
| December 31, 2018 | | | | | | | | | |
| Average Crude Oil and Condensate Price per Bbl | | | $ | 66.66 |
| | $ | 63.94 |
| | $ | 70.92 |
| | $ | 66.88 |
|
| Average Natural Gas Price per Mcf | | | 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 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 |
| | 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 |
| | $ | 37.36 |
| | $ | 36.05 |
| | $ | 42.45 |
| | $ | 37.87 |
|
| Average Natural Gas Price per Mcf | | 2.07 |
| | 5.07 |
| | 0.27 |
| | 3.02 |
| | 2.07 |
| | 5.07 |
| | 0.27 |
| | 3.02 |
|
| Average NGL Price per Bbl | | 14.30 |
| | — |
| | 26.12 |
| | 14.94 |
| | 14.30 |
| | — |
| | 26.12 |
| | 14.94 |
|
| December 31, 2015 | | | | | | | | | |
| Average Crude Oil and Condensate Price per Bbl | | $ | 42.03 |
| | $ | 48.23 |
| | $ | 51.03 |
| | $ | 43.50 |
| |
| Average Natural Gas Price per Mcf | | 2.16 |
| | 5.08 |
| | 0.27 |
| | 3.18 |
| |
| Average NGL Price per Bbl | | 14.15 |
| | — |
| | 29.92 |
| | 15.23 |
| |
The discounted future net cash flows are computed using a 12-month average commodity price applied to our year-end quantities of proved reserves, unless contractual arrangements designate the price to be used. We performed a sensitivity of our discounted future net cash flows to reflect a price reduction to our 12-month average commodity price. We estimate that a 10% per Bbl reduction in the average price of crude oil and NGLs from the 12-month average price for 20172018 would reduce the discounted future net cash flows before income taxes by approximately $1.2$1.6 billion and $0.3 billion, respectively. We estimate that a 10% per Mcf reduction in the average price of natural gas from the 12-month average price for 20172018 would reduce the discounted future net cash flows before income taxes by approximately $1$0.9 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 and NGL reserves at the end of the year, based on year-end costs, and assuming continuation of existing economic conditions.
Future development costs include amounts that we expect to spend to develop PUDs of approximately $1.7 billion in 2018, $1.9$2.1 billion in 2019, and $1.4$1.5 billion in 2020.2020 and $1.1 billion in 2021.
Future income tax expense is computed by applying the appropriate year-end statutory tax rates to the estimated future pre-tax net cash flows relating to proved crude oil, NGL and natural gas and NGL reserves, less the tax bases of the properties involved. Future income tax expense gives effect to tax credits and allowances, but does not reflect the impact of general and administrative costs and exploration expenses of ongoing operations.
|
| | |
| 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 and NGL reserves are as follows: | | | | | Year Ended December 31, | | | | | | | |
| | | 2017 | | 2016 | | 2015 | | Year Ended December 31, |
| (millions) | | | | | | | | 2018 | | 2017 | | 2016 |
| Standardized Measure of Discounted Future Net Cash Flows, Beginning of Year | | $ | 5,686 |
| | $ | 6,628 |
| | $ | 13,979 |
| | $ | 11,258 |
| | $ | 5,686 |
| | $ | 6,628 |
|
| Changes in Standardized Measure of Discounted Future Net Cash Flows | | | | | | | | | | | | |
| Sales of Oil and Gas Produced, Net of Production Costs | | (2,674 | ) | | (2,230 | ) | | (2,026 | ) | | (3,190 | ) | | (2,674 | ) | | (2,230 | ) |
Net Changes in Prices and Production Costs (1) | | 2,436 |
| | (593 | ) | | (12,603 | ) | | 2,327 |
| | 2,436 |
| | (593 | ) |
| Extensions, Discoveries and Improved Recovery, Less Related Costs | | 3,711 |
| | 463 |
| | 442 |
| | 2,036 |
| | 3,711 |
| | 463 |
|
| Changes in Estimated Future Development Costs | | (537 | ) | | (373 | ) | | 1,135 |
| | (738 | ) | | (537 | ) | | (373 | ) |
| Development Costs Incurred During the Period | | 1,975 |
| | 1,090 |
| | 2,639 |
| | 2,986 |
| | 1,975 |
| | 1,090 |
|
| Revisions of Previous Quantity Estimates | | 1,462 |
| | 364 |
| | (1,051 | ) | | (9 | ) | | 1,462 |
| | 364 |
|
Purchases of Minerals in Place (2) | | 423 |
| | 161 |
| | 2,747 |
| | — |
| | 423 |
| | 161 |
|
| Sales of Minerals in Place | | (643 | ) | | (951 | ) | | (46 | ) | |
Sales of Minerals in Place (3) | | | (1,873 | ) | | (643 | ) | | (951 | ) |
| Accretion of Discount | | 778 |
| | 919 |
| | 1,789 |
| | 1,538 |
| | 778 |
| | 919 |
|
Net Change in Income Taxes (3) | | (1,669 | ) | | 414 |
| | 2,075 |
| |
Change in Timing of Estimated Future Production and Other (4) | | 310 |
| | (206 | ) | | (2,452 | ) | |
Net Change in Income Taxes (4) | | | (11 | ) | | (1,669 | ) | | 414 |
|
| Change in Timing of Estimated Future Production and Other | | | (386 | ) | | 310 |
| | (206 | ) |
| Aggregate Change in Standardized Measure of Discounted Future Net Cash Flows | | $ | 5,572 |
| | $ | (942 | ) | | $ | (7,351 | ) | | $ | 2,680 |
| | $ | 5,572 |
| | $ | (942 | ) |
| Standardized Measure of Discounted Future Net Cash Flows, End of Year | | $ | 11,258 |
| | $ | 5,686 |
| | $ | 6,628 |
| | $ | 13,938 |
| | $ | 11,258 |
| | $ | 5,686 |
|
| |
(1) | The increaseincreases in 20172018 and the decrease in 20152017 were driven primarily by higher and lower, respectively, 12-month average commodity prices. |
| |
(2) | Purchase of minerals in 2017 relates to reserves acquired in the Clayton Williams Energy Acquisition. |
Purchase of minerals in 2015 relates to reserves acquired in the Rosetta Merger.
| |
(4) | The increase in 20172018 future income tax expense relates primarily to the increase in profit and levy taxes in Israel, partially offset by the decrease in future corporate income tax rate in Israel. The increase in profits tax is driven by a significant increase in future cash flows related to the Leviathan project sanctioning in 2017. The increase in US tax expense due to the increase inhigher future taxable income wasand 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 thea decrease in tax expense associated with utilizationfuture taxes in Israel driven by the sale of future net operating losses and decrease7.5% working interest in applicable tax rate from 35% to 21% due to the changes in the US Tax Law effective January 1, 2018. For 2015, future income tax expense for Israel includes the effect of estimated future profit levy taxes which partially offset the increase in future net cash flows. |
| |
(4)
| The decrease in 2015 reflects revisions in our estimated timing of production and development activity.Tamar. |
The increase in 2017 future income tax expense relates primarily to the increase in profit and levy taxes in Israel, partially offset by the decrease in future corporate income tax rate in Israel. The increase in profits tax is driven by a significant increase in future cash flows related to the Leviathan project sanctioning in 2017. The increase in US tax expense due to the increase in future taxable income was offset by the decrease in tax expense associated with utilization of future net operating losses and decrease in applicable tax rate from 35% to 21% due to the changes in the US Tax Law effective January 1, 2018.
|
| | |
| Noble Energy, Inc. | |
| Supplemental Quarterly Financial Information | |
| | (Unaudited) | |
Supplemental quarterly financial information is as follows: | | | | | Quarter Ended | | Quarter Ended |
| | | March 31, | | June 30, | | Sep 30, | | Dec 31, | | Total | | March 31, | | June 30, | | Sep 30, | | Dec 31, | | Total |
| (millions except per share amounts) | | | | | | | | | | | | | | | | | | | | |
2017 (1) (3) | | | | | | | | | | | |
2018 (1) (3) | | | | | | | | | | | |
| Revenues | | | $ | 1,286 |
| | $ | 1,230 |
| | $ | 1,273 |
| | $ | 1,197 |
| | $ | 4,986 |
|
| Income (Loss) Before Income Taxes | | | 543 |
| | 10 |
| | 307 |
| | (720 | ) | | 140 |
|
| Net Income (Loss) Including Noncontrolling Interests | | | 574 |
| | (6 | ) | | 248 |
| | (802 | ) | | 14 |
|
| Less: Net Income Attributable to Noncontrolling Interests | | | 20 |
| | 17 |
| | 21 |
| | 22 |
| | 80 |
|
| Net Income (Loss) Attributable to Noble Energy | | | 554 |
| | (23 | ) | | 227 |
| | (824 | ) | | (66 | ) |
| | | | | | | | | | | | |
| Net Income (Loss) Per Share, Basic | | | 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 | ) |
2017 (2) (3) | | | | | | | | | | | |
| Revenues | | $ | 1,036 |
| | $ | 1,059 |
| | $ | 960 |
| | $ | 1,201 |
| | $ | 4,256 |
| | $ | 1,036 |
| | $ | 1,059 |
| | $ | 960 |
| | $ | 1,201 |
| | $ | 4,256 |
|
| Income (Loss) Before Income Taxes | | 59 |
| | (2,334 | ) | | (208 | ) | | 292 |
| | (2,191 | ) | | 59 |
| | (2,334 | ) | | (208 | ) | | 292 |
| | (2,191 | ) |
| Net Income (Loss) | | 47 |
| | (1,498 | ) | | (115 | ) | | 516 |
| | (1,050 | ) | | 47 |
| | (1,498 | ) | | (115 | ) | | 516 |
| | (1,050 | ) |
| Less: Net Income Attributable to Noncontrolling Interests | | 11 |
| | 14 |
| | 21 |
| | 22 |
| | 68 |
| | 11 |
| | 14 |
| | 21 |
| | 22 |
| | 68 |
|
| Net Income (Loss) Attributable to Noble Energy | | 36 |
| | (1,512 | ) | | (136 | ) | | 494 |
| | (1,118 | ) | | 36 |
| | (1,512 | ) | | (136 | ) | | 494 |
| | (1,118 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Net Income (Loss) Per Share, Basic | | 0.08 |
| | (3.20 | ) | | (0.28 | ) | | 1.01 |
| | (2.38 | ) | | 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 | ) | | 0.08 |
| | (3.20 | ) | | (0.28 | ) | | 1.01 |
| | (2.38 | ) |
2016 (2) (3) | | | | | | | | | | | |
| Revenues | | $ | 724 |
| | $ | 847 |
| | $ | 910 |
| | $ | 1,010 |
| | $ | 3,491 |
| |
| Loss Before Income Taxes | | (453 | ) | | (498 | ) | | (280 | ) | | (541 | ) | | (1,772 | ) | |
| Net Income (Loss) | | (287 | ) | | (315 | ) | | (143 | ) | | (240 | ) | | (985 | ) | |
| Less: Net Income Attributable to Noncontrolling Interests | | — |
| | — |
| | 1 |
| | 12 |
| | 13 |
| |
| Net Loss Attributable to Noble Energy | | (287 | ) | | (315 | ) | | (144 | ) | | (252 | ) | | (998 | ) | |
| Net Loss Per Share, Basic and Diluted | | (0.67 | ) | | (0.73 | ) | | (0.33 | ) | | (0.59 | ) | | (2.32 | ) | |
(1) First quarter 2018 included the following:
| |
| • | $376 million pre-tax gain on sale of 7.5% working interest in Tamar field. See Note 5. Acquisitions and Divestitures; |
| |
| • | $196 million pre-tax gain on sale of our 50% interest in CONE Gathering. See Note 5. Acquisitions and Divestitures; |
| |
| • | $168 million impairment expense related to Gulf of Mexico asset divestiture. See Note 5. Acquisitions and Divestitures; |
| |
| • | $145 million discrete tax benefit, net, related to changes in federal income tax regulations. See Note 12. 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 2017 included the following:
| |
| • | $2.42.3 billion loss on Marcellus Shale upstream divestiture (See divestiture. See Note 4.5. Acquisitions Divestitures and Merger)Divestitures. |
Third quarter 2017 included the following:
| |
| • | $98 million loss on extinguishment of debt (See debt. See Note 10.9. Long-Term Debt). |
Fourth quarter 2017 included the following:
$270 million deferred tax benefit, net, related to recent changes in federal income tax regulations; and
| |
| • | $334 million gain on sale of mineral and royalty assets (See assets. See Note 4.5. Acquisitions Divestitures and Merger)Divestitures. |
(2)(3) FirstThe sum of the individual quarterly earnings (loss) may not agree with year-to-date earnings (loss) as each quarterly computation is based on the earnings (loss) for the individual quarter 2016 included the following:as reported with rounding applied.
$80 million gain on extinguishment of debt.
Second quarter 2016 included the following:
| |
• | $25 million purchase price allocation adjustment related to Rosetta Merger (See Note 4. Acquisitions, Divestitures and Merger). |
Third quarter 2016 included the following:
| |
• | $81 million undeveloped leasehold impairment expense (See Note6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs). |
Fourth quarter 2016 included the following:
| |
• | $579 million dry hole costs included in exploration expense (See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs); and |
| |
• | $92 million property impairment charges (See Note 5. Asset Impairments) |
| |
(3)
| The sum of the individual quarterly earnings (loss) may not agree with year-to-date earnings (loss) as each quarterly computation is based on the earnings (loss) for the individual quarter as reported with rounding applied.
|
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 “disclosuredisclosure controls and procedures” as such term is defined in Rule 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended, as of the end of the period covered by this Annual Report on Form 10-K. Based upon their evaluation, they have concluded that our disclosure controls and procedures were effective and provide an effective means to ensure that information required to be disclosed in the reports that we file or furnish under the Securities Exchange Actas of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms and that information is accumulated and communicated to management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that our controls will succeed in achieving their goals under all future conditions.December 31, 2018.
Management’s Annual Report on Internal Control over Financial Reporting
The management report called for by Item 308(a) of Regulation S-K is incorporated herein by reference to Management’s Report on Internal Control over Financial Reporting, included in Item 8. Financial Statements and Supplementary Data.
The independent auditor’s attestation report called for by Item 308(b) of Regulation S-K is incorporated herein by reference to Report of Independent Registered Public Accounting Firm (Internal Control Over Financial Reporting), included in Item 8.Financial Statements and Supplementary Data.
Changes in Internal Control over Financial Reporting
Our management is also responsible for establishing and maintaining adequate internal controls over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Our internal controls were designed to provide reasonable assurance as to the reliability of our financial reporting and the preparation and presentation of the consolidated financial statements for external purposes in accordance with US GAAP.
Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements. Projections of any evaluation of the effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Our management has assessed the effectiveness of our internal controls over financial reporting as of December 31, 2017. Based on our assessment, our internal controls over financial reporting were effective. There were no changes in internal controls over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.
Item 9B. Other Information
None.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.
153The 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.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
The information required by this item is incorporated herein by reference to the 20182019 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2017.2018.
Item 11. Executive Compensation
The information required by this item is incorporated herein by reference to the 20182019 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2017.2018.
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 20182019 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2017.2018.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this item is incorporated herein by reference to the 20182019 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2017.2018.
Item 14. Principal Accounting Fees and Services
The information required by this item is incorporated herein by reference to the 20182019 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2017.2018.
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) filed January 17, 2017 (File No. 001-07964) and incorporated herein by reference). |
| 2.2 | — | |
| 2.3 | — | |
| 2.4 | — | |
2.5 | — | |
2.6 | — | |
| 3.1 | — |
|
| 3.2 | — | |
| 3.3 | — |
|
| 3.4 | — |
|
| 4.1 | — | |
| 4.2 | — | |
| 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’sRegistrant'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’sRegistrant'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 | — | Seventh Supplemental Indenture dated as of August 15, 2017, to Indenture dated as of February 27, 2009 between Noble Energy, Inc. and Wells Fargo Bank, National Association, as Trustee, relating to senior debt securitiesthe Registrant's 3.850% Notes due 2028 and 4.950% Notes due 2047 (including the forms of Noble Energy, Inc.2028 Notes and 2027 Notes) (filed as Exhibit 4.1 to the Registrant’s Current Report on Form 8-K (Date of Report: August 15, 2017) filed August 15, 2017 (File No. 001-07964) and incorporated herein by reference). |
|
| | |
| 4.8 | — | Indenture dated as of October 14, 1993 between the Registrant and US Trust Company of Texas, N.A., as Trustee, relating to the Registrant’s 7¼%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) filed 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), filed 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), filed 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) filed October 9, 2013 (File No. 001-07964) and incorporated herein by reference). |
| 10.5 | — | Second Amendment to Credit Agreement, dated August 27, 2015, by and among Noble Energy, Inc., JPMorgan Chase Bank, N.A., as administrative agent, Citibank N.A., as syndication agent, and Bank of America, N.A., Bank of Tokyo-Mitsubishi UFJ, Ltd., Mizuho Bank, Ltd. and DNB Bank ASA, New York Branch as documentation agents, and the other commercial lending institutions party thereto (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Report: August 27, 2015) filed August 31, 2015 (File No. 001-07964) and incorporated herein by reference). |
| 10.6 | — | Term LoanThird Amendment to Credit Agreement, as of January 6, 2016dated March 9, 2018, by and among Noble Energy, Inc., Citibank,JPMorgan Chase Bank, N.A., as administrative agent, Mizuho Bank, Ltd.Citibank N.A., as syndication agent, and certain financialBank 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 as are or may become partiesparty thereto (filed as Exhibit 10.1 to the Registrant’sRegistrant's Current Report on Form 8-K (Date of Report: January 6, 2016)March 9, 2018) filed January 7, 2016March 12, 2018 (File No. 001-07964) and incorporated herein by reference). |
| 10.7* | — | |
|
| | |
| 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* | — | |
|
| | |
| 10.28* | — | |
| 10.29* | — | |
| 10.30* | — | |
| 10.31* | — | |
| 10.32* | — | |
| 10.33* | — | |
| 10.34* | — | |
| 10.35* | — | |
| 10.36* | — | |
| 10.37* | — | |
| 10.38* | — | |
| 10.39* | — | |
10.38*10.40* | — | |
10.39*10.41* | — | |
10.40*10.42* | — | |
10.41*10.43* | — | |
10.42*10.44* | — | |
10.43*10.45* | — | |
10.44*10.46* | — | |
|
| | |
10.46*10.48* | — | |
10.4710.49 | — | |
10.4810.50 | — | |
10.49*10.52 | — | |
10.50 | — | Support Agreement, dated as of January 13, 2017, by and among certain stockholders affiliated with Ares Management, LLC, Noble Energy, Inc., and solely for certain purposes specified therein, Clayton Williams Energy, Inc. (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Report: January 13, 2017) filed January 17, 2017 (File No. 001-07964) and incorporated herein by reference). |
10.5110.53 | — | Agreement Not to Dissent, dated as of January 13, 2017, by and among Clayton W. Williams, Jr., Noble
Energy, Inc., and solely for certain purposes specified therein, Clayton Williams Energy, Inc. (filed as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K (Date of Report: January 13, 2017) filed January 17, 2017 (File No. 001-07964) and incorporated herein by reference). |
10.5210.54 | — | Agreement Not to Dissent, dated as of January 13, 2017, by and among The Williams Children’s Partnership, Ltd., Noble Energy, Inc., and solely for certain purposes specified therein, Clayton Williams Energy, Inc. (filed as Exhibit 10.3 to the Registrant’s Current Report on Form 8-K (Date of Report: January 13, 2017) filed January 17, 2017 (File No. 001-07964) and incorporated herein by reference). |
10.53†10.55† | — | |
12.110.56 | — | |
2110.57*
| —
| |
| 21.1 | — | |
| 23.1 | — | |
| 23.2 | — | |
| 31.1 | — | |
| 31.2 | — | |
| 32.1 | — | |
| 32.2 | — | |
| 99.1 | — | |
| 101.INS | — | XBRL Instance Document |
| 101.SCH | — | XBRL Schema Document |
| 101.CAL | — | XBRL Calculation Linkbase Document |
| 101.LAB | — | XBRL Label Linkbase Document |
| 101.PRE | — | XBRL Presentation Linkbase Document |
| 101.DEF | — | XBRL Definition Linkbase Document |
|
| |
| * | Management contract or compensatory plan or arrangement required to be filed as an exhibit hereto. |
|
| |
| ** | Copies of exhibits will be furnished upon prepayment of 25 cents per page. Requests should be addressed to the 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
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 |
| 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 20, 201819, 2019 | By: /s/ David L. Stover |
| | | David L. Stover, |
| | | Chairman of the Board President and Chief Executive Officer |
| | | |
| Date: | February 20, 201819, 2019 | By: /s/ Kenneth M. Fisher |
| | | Kenneth M. Fisher, |
| | | Executive Vice President, Chief Financial Officer |
| | | |
| Date: | February 20, 201819, 2019 | 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 President and Chief Executive Officer | | February 20, 201819, 2019 |
| David L. Stover | | (Principal Executive Officer)
| | |
| | | | | |
| /s/ Kenneth M. Fisher | | Executive Vice President, Chief Financial Officer | | February 20, 201819, 2019 |
| Kenneth M. Fisher | | (Principal Financial Officer) | | |
| | | | | |
| /s/ Dustin A. Hatley | | Vice President, Chief Accounting Officer and Controller | | February 20, 201819, 2019 |
| Dustin A. Hatley | | (Principal Accounting Officer) | | |
| | | | | |
| /s/ Jeffrey L. Berenson | | Director | | February 20, 201819, 2019 |
| Jeffrey L. Berenson | | | | |
| | | | | |
| /s/ Michael A. Cawley | | Director | | February 20, 201819, 2019 |
| Michael A. Cawley | | | | |
| | | | | |
| /s/ Edward F. Cox | | Director | | February 20, 201819, 2019 |
| Edward F. Cox | | | | |
| | | | | |
| /s/ James E. Craddock | | Director | | February 20, 201819, 2019 |
| James E. Craddock | | | | |
| | | | |
| /s/ Barbara J. Duganier | | Director | | February 19, 2019 |
| Barbara J. Duganier | | | | |
| | | | | |
| /s/ Thomas J. Edelman | | Director | | February 20, 201819, 2019 |
| Thomas J. Edelman | | | | |
| | | | |
/s/ Kirby L. Hedrick | | Director | | February 20, 2018 |
Kirby L. Hedrick | | | | |
| | | | | |
| /s/ Holli C. Ladhani | | Director | | February 20, 201819, 2019 |
| Holli C. Ladhani | | | | |
| | | | | |
| /s/ Scott D. Urban | | Director | | February 20, 201819, 2019 |
| Scott D. Urban | | | | |
| | | | | |
| /s/ William T. Van Kleef | | Director | | February 20, 201819, 2019 |
| William T. Van Kleef | | | | |
| | | | |
/s/ Molly K. Williamson | | Director | | February 20, 2018 |
Molly K. Williamson | | | | |
