Item 1B.Unresolved Staff Comments
None.
Information regarding our properties is included in Item 1 of this report.
Item 3.
Item 3.Legal Proceedings
See Item 8 - Financial Statements and Supplementary Data-Note 10 of our Notes to Consolidated Financial Statements for the information that is called for by this item.
Item 4.
Item 4.Mine Safety Disclosures
Not applicable.
PART II
Item 5.
Item 5.Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is listed on the New York Stock Exchange under the ticker symbol “WPX.” The following table sets forth, for the periods indicated, the high and low sales prices per share of our common stock as reported by the New York Stock Exchange.
At February 26, 2020, there were 6,313 holders of record of our common stock.
We have not paid or declared any cash dividends on our common stock. Any decision as to future payment of dividends is subject to the discretion of our Board of Directors.
Stockholder Return Performance Presentation
The following stock performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the United States Securities and Exchange Commission, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933, as amended, or Securities Exchange Act of 1934, as amended, except to the extent that WPX specifically requests that such information be treated as “soliciting material” or specifically incorporates such information by reference into such a filing.
The performance graph below compares the cumulative five-year total return to stockholders on WPX’s common stock as compared to the cumulative five-year total returns on the Standard and Poor’s Midcap 400 Index (“MID”), and the Standard and Poor’s Oil and Gas Exploration and Production Select Industry Index (“S&P O&G”). The comparison assumed a $100 investment was made in WPX’s stock, the MID Index and the S&P O&G Index at the beginning of the period.
Unregistered Sales of Equity Securities and Use of Proceeds
a.Recent Sales of Unregistered Securities - Not applicable
b.Use of Proceeds - Not applicable.
c.Purchases of Equity Securities by the user and Affiliated Purchasers. The table below provides information about purchases of shares of our common stock during the quarter ended December 31, 2019.
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(a) On August 5, 2019, we announced that our Board of Directors authorized a plan to repurchase up to $400 million of our outstanding shares over a 24 month period. As of December 31, 2019 we have repurchased approximately 5.7 million shares at a total cost of $58 million. This stock repurchase program may be modified, suspended or terminated at any time by our Board of Directors.
Item 6.
Item 6.Selected Financial Data
The following financial data at December 31, 2019 and 2018, and for each of the three years ended December 31, 2019, 2018 and 2017 should be read in conjunction with the other financial information included in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and Part II, Item 8, Financial Statements and Supplementary Data of this Form 10-K. All other financial data has been prepared from our accounting records.
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(a) Income (loss) from continuing operations includes significant pre-tax items comprised of the following:
See Notes 4 and 5 of Notes to Consolidated Financial Statements for further discussion of asset sales and the equity method investment transactions in 2019, 2018 and 2017. In 2016, we completed the divestment of the remaining transportation contracts that were not included in the Piceance Basin divestment and recorded a net loss of $238 million. In 2015, we completed sales of a package of marketing contracts and released certain firm transportation capacity resulting in a $209 million gain. We also sold a North Dakota gathering system resulting in a $70 million gain and sold a portion of Appalachian properties resulting in a gain of $69 million.
(b) Income (loss) from discontinued operations includes the results of holdings in the San Juan Basin, holdings in the Piceance Basin and holdings in the Powder River Basin. Significant components included in income (loss) from discontinued operations are comprised of the following:
See Note 2 of Notes to Consolidated Financial Statements for further discussion of discontinued operations in 2019, 2018 and 2017.
Item 7.
Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations
General and Basis of Presentation
We are an independent oil and natural gas exploration and production company engaged in the exploitation and development of long-life unconventional properties. We are focused on profitably exploiting, developing and growing our oil positions in the Delaware Basin in Texas and New Mexico and the Williston Basin in North Dakota. Associated with our commodity production are sales and marketing activities, which include oil and natural gas purchased from third- party working interest owners in operated wells and the management of various commodity contracts such as transportation. The revenues and expenses related to these sales and marketing activities are reported on a gross basis as part of commodity management revenues and costs and expenses.
In late 2017 and early 2018, we divested our natural gas and oil properties in the San Juan Basin through two separate transactions. Subsequent to the closing of these transactions, we no longer have operations in the San Juan Basin. For all periods presented, the results of the San Juan Basin are reported as discontinued operations. See Note 2 of Notes to Consolidated Financial Statements for further discussion of our discontinued operations. Unless indicated otherwise, the following discussion relates to continuing operations.
The following discussion should be read in conjunction with the selected historical consolidated financial data and the consolidated financial statements and the related notes in Part II, Item 8, Financial Statements and Supplemental Data of this Form 10-K. See the Company's Annual Report on Form 10-K for the year ended December 31, 2018 for a discussion of the Company's 2018 results of operations as compared to the Company's 2017 results of operations. The matters discussed below may contain forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to these differences include, but are not limited to, those discussed below and elsewhere in this 10-K, particularly in “Risk Factors” and “Forward-Looking Statements.”
Overview
Composition of Production (based on Mboe) and Product Revenue
ProductionProduct Revenue
The following table presents our production volumes and financial highlights for 2019, 2018 and 2017:
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Our 2019 operating results were $410 million unfavorable compared to 2018. The primary items impacting 2019 results compared to 2018 results include:
•$234 million unfavorable change in net gain (loss) on derivatives; and
•$350 million higher operating costs including depreciation, depletion and amortization, lease and facility, gathering, processing and transportation, and taxes other than income.
Offset by:
•$222 million increase in product revenues, primarily oil sales. Overall, $584 million related to higher production sales volumes substantially offset by $362 million related to lower sales prices.
Outlook
After our multi-year transformation of WPX, our oil-prone positions in the Delaware (Permian) and Williston Basins now form the foundation of WPX. Our acreage positions in each of these basins contains some of the premier geology in the plays and in North America. Over the same period, we also assembled an attractive infrastructure portfolio in the Permian, which will help flow our production out of the basin and will create additional value either through monetization of our midstream investments or lower operating costs. In addition to our joint venture with Howard Energy Partners LLC, we made additional investments during 2018 in our equity positions in two companies that own pipeline systems in the Delaware Basin. In 2019, we closed on transactions and monetized the value in those equity positions totaling approximately $500 million and utilized those proceeds to reduce debt. In addition to these monetizations and debt reduction, WPX took other steps to enhance its value proposition, including launching a share buyback program, generating free cash flow and lowering our weighted-average interest rate on long-term debt.
In the latter half of 2019, we communicated a vision for the Company, which included, among other items, implementing a meaningful dividend, targeting a 7% to 10% free cash flow yield and driving down our leverage metric from current levels. Our focus is, in part, on the important metrics that will drive investor interest over the next 5 years and allow us to compete against any sector, not just energy.
In December 2019, we entered into an agreement with Felix Investments Holdings II, LLC ("Felix Parent") to acquire all of the issued and outstanding membership interests of Felix Energy Holdings II, LLC, or Felix (collectively, the "Felix Acquisition"), for consideration of approximately $2.5 billion ("Purchase Price"), consisting of $900 million in cash (such amount the "Unadjusted Cash Purchase Price") and 152,963,671 unregistered shares of our common stock determined by dividing $1.6 billion by $10.46 (the volume weighted-average price per share price of the Company for the ten consecutive days ending on December 13, 2019) (the "Unadjusted Equity Consideration"). The Purchase Price is subject to customary closing adjustments. See Note 17 of Notes to Consolidated Financial Statements for further discussion of the Felix Acquisition. The Felix Acquisition is consistent with the tenets in our 5-year vision and will allow us to accomplish these objectives more quickly and efficiently thru this highly de-risked, leverage neutral transaction. We plan to implement a dividend following the integration of Felix, targeting approximately $0.10 per share on an annualized basis at initiation. To fund the cash portion of the Felix Acquisition, we completed a January 2020 offering of $900 million of 4.50% Senior Notes due in 2030, the proceeds of which are held in escrow until the closing of the Felix Acquisition.
Our expected base full-year 2020 capital budget, including the impact of the Felix Acquisition assuming a late first quarter or early second quarter closing and excluding land purchases, is $1.675 billion to $1.8 billion. Planned capital for drilling and completions, including non-operated wells, is $1.625 billion to $1.725 billion for the full year 2020, with an additional $50 million to $75 million in midstream opportunities in the Delaware Basin.
Our liquidity at December 31, 2019 totaled approximately $1.5 billion, reflecting amounts available under the Credit Facility Agreement and cash on hand. Our next Senior Note maturity of $73 million is not due until 2022. As of this filing and before consideration of the Felix Acquisition, our Credit Facility Agreement is subject to a $2.1 billion borrowing base with aggregate elected commitments of $1.5 billion and a maturity date of April 17, 2023 (see Note 8 of Notes to Consolidated Financial Statements for further discussion). We believe our current liquidity position will provide the necessary capital to develop our assets or should sustain us if there is a downturn.
Overall, we believe we are well positioned for prudent and disciplined growth assuming a constructive commodity price environment. However, the challenging and dynamic environment of the oil and gas industry, along with future market conditions, may alter these expectations or plans. If we foresee other-than-temporary changes in market conditions, including significant fluctuation in expected commodity prices, we will evaluate the appropriateness of adjustments to our plans.
As we execute on our long-term strategy, we continue to operate with a focus on increasing shareholder value and investing in our businesses in a way that enhances our competitive position by:
•sustainable, value driven and environmentally responsible development of our positions in the Delaware and Williston Basins;
•successful integration of Felix;
•continuing to pursue cost improvements and efficiency gains;
•employing new technology and operating methods;
•continuing to invest in projects to assess resources and add new development opportunities or opportunistic acquisitions to our portfolio;
•retaining the flexibility to make adjustments to our planned levels and allocation of capital investment expenditures in response to changes in economic conditions or business opportunities; and
•continuing to maintain an active economic hedging program around our commodity price risks.
Potential risks or obstacles that could impact the execution of our plan include:
•lower than anticipated energy commodity prices;
•inability to successfully integrate Felix’s operations or to realize cost savings, revenues or other anticipated benefits of the Felix Acquisition;
•increase in the cost of, or shortages or delays in the availability of, drilling rigs and equipment supplies, skilled labor or transportation;
•higher capital costs of developing our properties, including the impact of inflation;
•lower than expected levels of cash flow from operations;
•counterparty credit and performance risk;
•general economic, financial markets or industry downturn;
•unavailability of capital either under our revolver or access to capital markets;
•changes in the political and regulatory environments; and
•decreased drilling success.
We continue to address certain of these risks through utilization of commodity hedging strategies, disciplined investment strategies and maintaining adequate liquidity. In addition, we use master netting agreements and collateral requirements with our counterparties to reduce credit risk and liquidity requirements. Further, we continue to monitor the long-term market outlooks and forecasts for potential indicators of needed changes to our forecasted oil and natural gas prices. Commodity prices are volatile and prices for a barrel of oil ranged from over $100 per barrel to less than $30 per barrel since 2014. Our forecasted price assumptions reflect a long-term view of pricing but also consider current prices and are consistent with pricing assumptions generally used in evaluating our drilling decisions and acquisition plans. If forecasted oil and natural gas prices were to decline, we would need to review the producing properties net book value for possible impairment. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges will be recorded. If impairments were required, the charges could be significant. The net book value of our proved properties is $5.9 billion. In addition, the net book value associated with unproved leasehold is approximately $1.6 billion and is primarily associated with our Delaware Basin properties. See our discussion of impairment of long-lived assets in our Critical Accounting Estimates discussion later in this section.
Results of Operations
2019 vs. 2018
Revenue Analysis
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NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.
Significant variances in the respective line items of revenues are comprised of the following:
•$260 million increase in oil sales reflects $485 million related to higher production sales volumes partially offset by $225 million related to lower sales prices for 2019 compared to 2018. The increase in production sales volumes was primarily driven by our Williston Basin. The Williston Basin volumes increased 41 percent to 57.2 MBbls per day from 40.6 MBbls per day for 2019 and 2018, respectively. The Delaware Basin volumes increased 13 percent to 46.4 MBbls per day from 41.0 MBbls per day for 2019 and 2018, respectively. The following table reflects oil production prices, the price impact of our derivative settlements and volumes for 2019 and 2018.
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(a) Included in net gain (loss) on derivatives on the Consolidated Statements of Operations.
•$12 million decrease in natural gas sales reflects $39 million decrease related to lower gas sales prices for 2019 compared to 2018, partially offset by $27 million increase related to higher production sales volumes for 2019 compared to 2018. The increase in our production sales volumes primarily relates to our Delaware Basin, which had production volumes of 173.0 MMcf per day for 2019 compared to 137.7 MMcf per day for 2018. The following table reflects natural gas production prices, the price impact of our derivative settlements and volumes for 2019 and 2018.
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(a) Included in net gain (loss) on derivatives on the Consolidated Statements of Operations.
•$26 million decrease in natural gas liquids sales primarily reflects $99 million related to lower NGL sales prices partially offset by $73 million related to higher production sales volumes for 2019 compared to 2018. The Delaware Basin volumes were 20.8 MBbls per day compared to 14.2 MBbls per day for 2019 and 2018, respectively. The Williston Basin volumes were 6.8 MBbls per day compared to 4.2 MBbls per day for 2019 and 2018, respectively. The following table reflects NGL production prices, the price impact of our derivative settlements and volumes for 2019 and 2018.
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(a) Included in net gain (loss) on derivatives on the Consolidated Statements of Operations.
•$234 million unfavorable change in net gain (loss) on derivatives primarily reflects changes in crude oil derivatives that were a result of increases in 2019 of forward commodity prices relative to our hedge positions. Settlements to be received on derivatives totaled $12 million for 2019 and settlements to be paid totaled $237 million for 2018.
•$10 million decrease in commodity management revenues primarily due to lower crude sales volumes and lower prices on crude and natural gas sales. These decreases are offset by higher natural gas sales volumes in 2019 as a result of additional excess capacity in the Delaware Basin, which we utilized to purchase natural gas at depressed Delaware Basin pricing and transport to sales points outside the Basin. Related commodity management costs and expenses decreased $19 million and are discussed below.
Cost and operating expense and operating income analysis:
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NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.
Significant components on our costs and expenses are comprised of the following:
•$151 million increase in depreciation, depletion and amortization is primarily due to higher production volumes partially offset by a $1.52 decrease in the per Boe rate compared to 2018 primarily due to favorable technical revisions
in the Williston Basin. The decrease in the per Boe rate was also a result of the addition of new wells with lower relative cost per Boe.
•$102 million increase in lease and facility operating expenses primarily related to increased production volumes and higher water management costs for 2019 compared to 2018.
•$76 million increase in gathering, processing and transportation is due to growth in production volumes and the impact of new or modified contracts in the Delaware and Williston Basins.
•$21 million increase in taxes other than income related to increased product revenues, previously discussed.
•$20 million increase in exploration expenses is primarily due to higher unproved leasehold amortization in 2019.
•$24 million increase in general and administrative expenses for 2019 compared to 2018. General and administrative expenses in 2019 included $8 million for costs associated with a voluntary exit program we offered to employees. Also included in the increase is approximately $10 million higher employee incentive bonus compared to 2018. Our general and administrative expenses per BOE decreased to an average $3.40 for 2019 compared to $3.92 for 2018. Excluding the $8 million related to the voluntary exit program, our rate per Boe averaged $3.27 in 2019.
•$19 million decrease in commodity management expenses is primarily due to lower crude purchase volumes and depressed Delaware Basin pricing on physical natural gas cost of sales. These decreases are partially offset by higher natural gas sales volumes as discussed above.
•$11 million increase in other expense for 2019 compared to 2018 primarily related to an $11 million charge in 2019 associated with an offer made by us to settle certain contractual disputes in the Williston Basin (See Note 4 of Notes to Consolidated Financial Statements for details of this expense).
Results below operating income
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NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.
Interest expense decreased in 2019 compared to 2018 due to a lower amount of average debt outstanding in 2019 and lower average interest rates. Offsetting these decreases was approximately $3 million of fees for a bridge facility related to the Felix Acquisition.
In the third quarter of 2019, we issued $600 million of Senior Notes due in 2027. The net proceeds from this offering were used to fund the purchase of $550 million aggregate principal amount of our 2022 Notes and 2023 Notes. As a result of the early retirement of these Senior Notes, we recorded a loss on extinguishment of debt of $47 million in 2019. In the second quarter of 2018, we used proceeds from the San Juan Gallup disposition and proceeds from the issuance of $500 million of Senior Notes due in 2026 to retire $921 million aggregate principal amount of our Senior Notes. As a result of the early retirement of these Senior Notes, we recorded a loss on extinguishment of debt of $71 million in 2018. See Note 8 of Notes to Consolidated Financial Statements for additional information regarding these transactions.
Gains on equity method investments transactions in 2019 related to the sale of our 20 percent equity interest in the Whitewater natural gas pipeline and a distribution received related to our 25 percent equity interest in the Oryx pipeline. See Note 5 of Notes to Consolidated Financial Statements for details of these transactions.
Loss from discontinued operations in 2018 primarily relates to a $147 million pretax loss on the sale of our San Juan
Gallup operations, which was sold in the first quarter of 2018. See Note 2 of Notes to Consolidated Financial Statements for detail of amounts included in discontinued operations.
Management’s Discussion and Analysis of Financial Condition and Liquidity
Overview and Liquidity
We expect our capital structure will provide us financial flexibility to meet our requirements for working capital and capital expenditures while maintaining a sufficient level of liquidity. Our primary sources of liquidity in 2020 are cash on hand, expected cash flows from operations, contributions from noncontrolling interests (see Note 14 of Notes to Consolidated Financial Statements), and, if necessary, borrowings on our credit facility. We anticipate that the combination of these sources should be sufficient to allow us to pursue our business strategy and goals through at least 2020. These goals include implementing a meaningful dividend, targeting a 7 percent to 10 percent free cash flow yield, driving down our leverage metrics from current levels and continuing to opportunistically repurchase our shares. Additional sources of liquidity, if needed and if available, include proceeds from asset sales, bank financings and proceeds from the issuance of long-term debt and equity securities.
We note the following assumptions for 2020:
•our planned capital expenditures, excluding acquisitions, are estimated to be approximately $1.675 billion to $1.8 billion of which $1.625 billion to $1.725 billion relates to drilling and completions, including facilities; and
•we have hedged a portion of our anticipated 2020 oil and gas production as disclosed in Commodity Price Risk Management following this section.
Potential risks associated with our planned levels of liquidity and the planned capital expenditures discussed above include:
•lower than expected levels of cash flow from operations, primarily resulting from lower energy commodity prices or inflation on operating costs;
•our ability to successfully integrate Felix's operation or to realize costs savings, revenues or other anticipated benefits of the Felix Acquisition;
•significantly lower than expected capital expenditures could result in the loss of undeveloped leasehold;
•reduced access to our credit facility pursuant to our financial covenants; and
•higher than expected development costs, including the impact of inflation.
Credit Facility
Our Credit Facility (as defined in Note 8 of Notes to Consolidated Financial Statements), includes total commitments of $1.5 billion, on a $2.1 billion Borrowing Base with a maturity date of April 17, 2023. Based on our current credit ratings, a Collateral Trigger Period applies that makes the Credit Facility subject to certain financial covenants and a Borrowing Base. The Credit Facility may be used for working capital, acquisitions, capital expenditures and other general corporate purposes. The financial covenants in the Credit Facility may limit our ability to borrow money, depending on the applicable financial metrics at any given time. For additional information regarding the terms of our Credit Facility see Note 8 of Notes to Consolidated Financial Statements. As of December 31, 2019, WPX had no borrowings outstanding and $28 million of letters of credit issued under the Credit Facility. Additionally, WPX was in compliance with our covenants under the Credit Facility as of December 31, 2019. Our unused borrowing availability was $1,472 million as of December 31, 2019.
Strategic Partnerships
In September and October 2019, we entered into strategic relationships with two third-parties through two newly-formed subsidiaries for purposes of acquiring mineral interests and funding participation in future non-operated well interests. In accordance with and subject to the terms of the agreements, both parties have committed to fund future contributions, subject to certain limits, through the end of 2020 and 2022, respectively. The third-party contributions would represent 80 percent to 85 percent of the total contributions to the partnerships. WPX will be entitled to receive varying percentages of returns based upon achievement of certain predetermined thresholds.
Pending Felix Acquisition
As previously discussed, we signed an agreement in December 2019 to purchase Felix Investments Holdings II, LLC for $2.5 billion. The closing is expected in first-quarter 2020. The $900 million cash portion and transaction costs at closing will be funded by the proceeds from the senior notes discussed below and, if necessary, our Credit Facility.
On January 10, 2020, we completed our debt offering of $900 million aggregate principal amount of 4.50% senior unsecured notes due 2030. The proceeds were deposited into an escrow account upon the closing of the offering. Upon release
from escrow, WPX intends to use the proceeds to finance a portion of the cash consideration of the Felix Acquisition and to pay certain fees and expenses (see Note 17 of Notes to Consolidated Financial Statements).
Commodity Price Risk Management
To manage the commodity price risk and volatility of owning producing oil and gas properties, we enter into derivative contracts for a portion of our future production (see Note 16 of Notes to Consolidated Financial Statements). We chose not to designate our derivative contracts associated with our future production as cash flow hedges for accounting purposes. We have the following contracts as of the date of this filing shown at weighted average volumes and basin-level weighted average prices:
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(a) Fixed Price Swaps include hedges related to a new partnership created to fund non-operated interests.
Credit Ratings
Our ability to borrow money will be impacted by several factors, including our credit ratings. Credit ratings agencies perform independent analyses when assigning credit ratings. While not a current factor related to our Credit Facility, a downgrade of our current rating could increase our future cost of borrowing, thereby negatively affecting our available liquidity. The ratings as of February 26, 2020 were as follows:
At the time of the Felix Acquisition announcement or shortly thereafter, all three credit rating agencies indicated that WPX could receive credit rating upgrades following the closing of the Felix Acquisition.
Sources (Uses) of Cash
Operating activities
Net cash provided by operating activities increased in 2019 from 2018 primarily due to higher production volumes in 2019 and realizations on our derivatives, partially offset by higher operating costs and lower commodity prices. Additionally, 2019 includes the receipt of approximately $38 million related to an alternative minimum tax credit refund (see Note 9 of Notes to Consolidated Financial Statements).
Net cash provided by operating activities increased in 2018 from 2017 primarily due to higher production volumes and higher commodity prices in 2018, partially offset by higher operating costs and an increase in settlements paid on our derivatives.
Total cash provided by operating activities related to discontinued operations excluding changes in working capital was approximately $44 million and $143 million for 2018 and 2017, respectively. Cash outflows related to previous accruals for Powder River Basin gathering and transportation contracts retained were $28 million, $47 million and $53 million for 2019, 2018 and 2017, respectively.
Investing activities
The table below reflects capital expenditures, exclusive of partnerships, for the periods presented.
Incurred capital expenditures related to partnerships was approximately $8 million in 2019.
Significant components related to proceeds from the sale of our assets are comprised of the following:
•$505 million of proceeds related to transactions involving our equity method investments including our 20 percent equity interest in Whitewater natural gas pipeline and our 25 percent equity interest in the Oryx pipeline (see Note 5 of Notes to Consolidated Financial Statements); and
•$83 million in proceeds from the sale of certain non-core properties (see Note 4 of Notes to Consolidated Financial Statements).
•$645 million of net proceeds from the sale of San Juan Gallup (see Note 2 of Notes to Consolidated Financial Statements).
•$155 million related to the sale of our natural gas-producing properties in the San Juan Basin (see Note 2 of Notes to Consolidated Financial Statements).
Net cash used in investing activities for 2018 includes $102 million of additional investment in equity method investments. Net cash used in investing activities for the year ended December 31, 2017 includes $798 million related to the acquisition of acreage in the Delaware Basin.
Investing activities in 2017 includes net proceeds of $338 million from the formation of the joint venture with Howard (see Note 5 of Notes to Consolidated Financial Statements).
Financing activities
The following are significant financing activities by year:
•$594 million of payments for retirement of long-term debt, including approximately $44 million of premium, offset by $593 million net proceeds from a debt issuance in the third quarter of 2019. See Note 8 of Notes to Consolidated Financial Statements for further discussion of our debt tender offers and debt issuance;
•$330 million of net repayments on the Credit Facility; and
•$58 million of payments for repurchases of common stock under a share repurchase program approved by the Board of Directors in third-quarter 2019 (see Note 14 of Notes to Consolidated Financial Statements).
•$986 million of payments for retirement of long-term debt, including approximately $63 million of premium, partially offset by $494 million net proceeds from a debt issuance in the second quarter of 2018. See Note 8 of Notes to Consolidated Financial Statements for further discussion of our debt tender offers and debt issuance;
•$330 million net borrowings on the Credit Facility; and
•$11 million of preferred stock dividends.
•In January 2017, we completed an equity offering of 51.675 million shares for net proceeds of approximately $670 million in conjunction with the acquisition of acreage in the Delaware Basin;
•$15 million of preferred stock dividends; and
•payment of $165 million, including premium, to repurchase some of our 2020 Senior Notes partially offset by $148 million of net proceeds related to the issuance of additional notes due 2024.
Off-Balance Sheet Financing Arrangements
We had no guarantees of off-balance sheet debt to third parties or any other off-balance sheet arrangements at December 31, 2019 and December 31, 2018. Although not a financing arrangement, we have provided a guarantee for certain obligations transferred as part of a 2018 divestment (see Note 2 of Notes to Consolidated Financial Statements).
Contractual Obligations
The table below summarizes the maturity dates of our contractual obligations at December 31, 2019.
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(a) Includes materials and services obligations associated with our drilling rig contracts.
(b) Includes firm demand obligations of $22 million of which $21 million is recorded as a liability as of December 31, 2019. A liability was recorded in 2015 in conjunction with our exit from the Powder River Basin (see Note 2 of Notes to Consolidated Financial Statements). Excludes additional commitments totaling $875 million associated with projects for which a counterparty has not completed construction.
(c) Includes gathering, processing and other oil and gas related services commitments of $17 million of which $15 million is recorded as a liability as of December 31, 2019. Liabilities were recorded in 2015 in conjunction with our exit from the Powder River Basin and associated with an abandoned area in the Appalachian Basin.
(d) Excluded are liabilities associated with asset retirement obligations totaling $97 million as of December 31, 2019. The ultimate settlement and timing of asset retirement obligations cannot be precisely determined in advance; however, we estimate that approximately 21 percent of this liability will be settled in the next five years.
(e) Obligations for financial derivatives are based on market information as of December 31, 2019, and assume contracts remain outstanding for their full contractual duration. Because market information changes daily and is subject to volatility, significant changes to the values in this category may occur.
Effects of Inflation
Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy. Operating costs are influenced by both competition for specialized services and specific price changes in oil, natural gas, NGLs and other commodities. We tend to experience inflationary pressure on the cost of services and equipment when higher oil and gas prices cause an increase in drilling activity in our areas of operation. Likewise, lower prices and reduced drilling activity may lower the costs of services and equipment.
Environmental
Our operations are subject to governmental laws and regulations relating to the protection of the environment, and increasingly strict laws, regulations and enforcement policies, as well as future additional environmental requirements, could materially increase our costs of operation, compliance and any remediation that may become necessary. In view of (1) trends in public and political sentiment regarding environmental expectations; (2) a desire to continually improve our environmental performance; and (3) elevating attention on emerging public policy, our board added responsibilities to our Nominating and Governance Committee and changed the name to the Nominating, Governance, Environmental & Public Policy Committee. This is a recognition of the reality that new standards and requirements will emerge for producers of traditional energy. The Committee’s amended charter provides for (1) overseeing management’s monitoring and enforcement of WPX’s policies to protect the environment, including those related to flaring and emissions; (2) monitoring emerging political, social and environmental trends and major global legislative and regulatory developments that may affect or require adjustments in our business operations; and (3) advising the Board of Directors on significant stakeholder concerns and shareholder proposals relating to environmental, public policy or sustainability-related matters.
Critical Accounting Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. We believe that the nature of these estimates and assumptions is material due to the subjectivity and judgment necessary, the susceptibility of such matters to change, and the impact of these on our financial condition or results of operations.
In our management’s opinion, the more significant reporting areas impacted by management’s judgments and estimates are as follows:
Successful Efforts Method of Accounting for Oil and Gas Exploration and Production Activities
We use the successful efforts method of accounting for our oil- and gas-producing activities. Estimated oil and natural gas reserves and estimated market prices for oil and gas are a significant part of our financial calculations. Following are examples of how these estimates affect financial results:
•an increase (decrease) in estimated proved oil, natural gas and NGL reserves can reduce (increase) our unit-of-production depreciation, depletion and amortization rates; and
•changes in oil, natural gas, and NGL reserves and estimated market prices both impact projected future cash flows from our properties. This, in turn, can impact our periodic impairment analyses.
The process of estimating oil and natural gas reserves is very complex, requiring significant judgment in the evaluation of all available geological, geophysical, engineering and economic data. After being estimated internally, approximately 100 percent of our reserves estimates are audited by independent experts. The data may change substantially over time as a result of numerous factors, including the historical 12 month weighted average price, additional development cost and activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserves estimates could occur from time to time. Such changes could trigger an impairment of our oil and gas properties and have an impact on our depreciation, depletion and amortization expense prospectively. For example, a change of approximately 10 percent in our total oil and gas reserves could change our annual depreciation, depletion and amortization expense between approximately $83 million and $101 million. The actual impact would depend on the specific basins impacted and whether the change resulted from proved developed, proved undeveloped or a combination of these reserves categories.
Estimates of future commodity prices, which are utilized in our impairment analyses, consider market information including published forward oil and natural gas prices. The forecasted price information used in our impairment analyses is consistent with that generally used in evaluating our drilling decisions and acquisition plans. Prices for future periods impact the production economics underlying oil and gas reserve estimates. In addition, changes in the price of oil and natural gas also impact certain costs associated with our underlying production and future capital costs. The prices of oil and natural gas are volatile and change from period to period, thus impacting our estimates. Significant unfavorable changes in the estimated future commodity prices could result in an impairment of our oil and gas properties. See impairments of long-lived assets below.
We record the cost of leasehold acquisitions as incurred. Individually significant lease acquisition costs are assessed annually, or as conditions warrant, for impairment considering our future drilling plans, the remaining lease term and recent drilling results. Lease acquisition costs that are not individually significant are aggregated by prospect or geographically, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. Changes in our assumptions regarding the estimates of the nonproductive portion of these leasehold acquisitions could result in impairment of these costs. Upon determination that specific acreage will not be developed, the costs associated with that acreage would be impaired. Additionally, our leasehold costs are evaluated for impairment if the proved property costs in the basin are impaired. Our capitalized lease acquisition costs totaled $1.6 billion at December 31, 2019 and are primarily associated with our Delaware Basin acreage.
Impairments of Long-Lived Assets
We evaluate our long-lived assets for impairment when we believe events or changes in circumstances indicate that we may not be able to recover the carrying value. When an indicator of impairment has occurred, we compare our estimate of undiscounted cash flows attributable to the assets to the carrying value of the assets to determine if an impairment has occurred. If an impairment has occurred, we determine the amount of impairment by estimating the fair value of the assets. Our computations utilize judgments and assumptions that include estimates of the undiscounted future cash flows, discounted future cash flows, estimated fair value of the asset, and the current and future economic environment in which the asset is operated.
We assess our proved properties for impairment using estimates of future undiscounted cash flows. Significant judgments and assumptions are inherent in these assessments and include estimates of reserves quantities, estimates of future commodity prices (developed in consideration of market information, internal forecasts and published forward prices adjusted for locational
basis differentials), drilling plans, expected capital and lease operating costs. The assessment performed as of December 31, 2019 did not identify any properties with a carrying value in excess of those estimated undiscounted cash flows. Therefore, no impairment charges were recorded in 2019 based on this assessment.
The assessments described above included approximately $5.9 billion of net book value associated with our proved properties. Many judgments and assumptions are inherent and to some extent interdependent of one another in our estimate of future cash flows used to evaluate these assets. The use of alternate judgments and assumptions could result in the recognition of different levels of impairment charges in the consolidated financial statements. As previously noted within “Successful Efforts Method of Accounting for Oil and Gas Exploration and Production Activities”, estimated natural gas and oil reserves and estimated future commodity prices for oil and gas are a significant part of our impairment analysis. Commodity prices are significantly volatile and prices for a barrel of oil ranged from over $100 per barrel to less than $30 per barrel since 2014. Our forecasted price assumptions reflect a long-term view of pricing but also consider current prices and are consistent with pricing assumptions generally used in evaluating our drilling decisions and acquisition plans. Approximately 56 percent of our future production considered in the impairment assessment is in years 2025 and beyond. If the estimated commodity revenues (only one of the many estimates involved) of the predominately oil proved properties were lower by 15 to 25 percent, these properties could be at risk for impairment. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges will be recorded. If impairments were required, the charges could be significant.
Valuation of Deferred Tax Assets and Liabilities
We record deferred taxes for the differences between the tax and book basis of our assets and liabilities as well as loss or credit carryovers to future years. Included in our deferred taxes are deferred tax assets primarily resulting from certain federal and state tax loss carryovers generated in the current and prior years and alternative minimum tax credits. We must periodically evaluate whether it is more likely than not we will realize these deferred tax assets and establish a valuation allowance for those that do not meet the more likely than not threshold. When assessing the need for a valuation allowance, we primarily consider future reversals of existing taxable temporary differences. To a lesser extent, we may also consider future taxable income exclusive of reversing temporary differences and carryovers, and tax-planning strategies that would, if necessary, be implemented to accelerate taxable amounts to utilize expiring carryovers. The ultimate amount of deferred tax assets realized could be materially different from those recorded, as influenced by future operational performance, potential changes in jurisdictional income tax laws and other circumstances surrounding the actual realization of related tax assets.
As of December 31, 2019, our assessment of federal net operating loss carryovers was that no valuation allowance was required; however, a future pretax loss or limitation due to an ownership change may result in the need for a valuation allowance on our deferred tax assets.
The determination of our state deferred tax liability requires judgment as our state deferred tax rates can change periodically based on changes in our operations. Our state deferred tax rates are based upon our current entity structure, the jurisdictions in which we operate and corresponding statutory tax rates.
Fair Value Measurements
A small portion of our energy derivative assets and liabilities trade in markets with limited availability of pricing information requiring us to use unobservable inputs and are considered Level 3 in the fair value hierarchy. For Level 2 transactions, we do not make significant adjustments to observable prices in measuring fair value as we do not generally trade in inactive markets.
The determination of fair value for our energy derivative assets and liabilities also incorporates the time value of money and various credit risk factors, which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our energy derivative liabilities. The determination of the fair value of our energy derivative liabilities does not consider noncash collateral credit enhancements. For net derivative assets, we apply a credit spread, based on the credit rating of the counterparty, against the net derivative asset with that counterparty. For net derivative liabilities, we apply our own credit rating. We derive the credit spreads by using the corporate industrial credit curves for each rating category and building a curve based on certain points in time for each rating category. The spread comes from the discount factor of the individual corporate curves versus the discount factor of the LIBOR curve. At December 31, 2019, the credit reserve is less than $1 million on our net derivative assets and net derivative liabilities. Considering these factors and that we do not have significant risk from our net credit exposure to derivative counterparties, the impact of credit risk is not significant to the overall fair value of our derivatives portfolio.
Of the $24 million net derivative liability at December 31, 2019, $34 million of liability expires in the next 12 months. Our derivatives portfolio is largely comprised of exchange-traded products or like products where price transparency has not historically been a concern. Due to the nature of the markets in which we transact and the relatively short tenure of our
derivatives portfolio, we do not believe it is necessary to make an adjustment for illiquidity. We regularly analyze the liquidity of the markets based on the prevalence of broker pricing and exchange pricing for products in our derivatives portfolio.
There were no instruments included in Level 3 at December 31, 2019.
For the year ended December 31, 2017, we recognized an impairment in discontinued operations on natural gas-producing properties held for sale in the San Juan Basin as a result of comparing our book value to the estimated fair value, less costs to sell, based on the probability-weighted cash flows of expected sales proceeds. In conjunction with exchanges of leasehold, we estimated the fair value of the leasehold through discounted cash flow models and consideration of market data. See Note 15 of Notes to Consolidated Financial Statements.
Contingent Liabilities
We record liabilities for estimated loss contingencies, including royalty litigation, environmental and other contingent matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. Liabilities for contingent losses are based upon our assumptions and estimates and upon advice of legal counsel, engineers or other third parties regarding the probable outcomes of the matter. As new developments occur or more information becomes available, our assumptions and estimates of these liabilities may change. Changes in our assumptions and estimates or outcomes different from our current assumptions and estimates could materially affect future results of operations for any particular quarterly or annual period. See Note 10 of Notes to Consolidated Financial Statements.
Item 7A.
Item 7A.Quantitative and Qualitative Disclosures About Market Risk
Interest Rate Risk
Our interest rate risk exposure is related primarily to our debt portfolio. Our senior notes are fixed rate debt in order to mitigate the impact of fluctuations in interest rates. For our fixed rate debt, $73 million matures in 2022, $406 million matures in 2023, $650 million matures in 2024, $500 million matures in 2026 and $600 million matures in 2027. Interest rates for each group are 6.00 percent, 8.25 percent, 5.25 percent, 5.75 percent and 5.25 percent, respectively. The aggregate fair value of the senior notes is $2,400 million. Borrowings under our Credit Facility are based on a variable interest rate and could expose us to the risk of increasing interest rates. As of December 31, 2019, we had no borrowings outstanding under the Credit Facility. See Note 8 of Notes to Consolidated Financial Statements.
Commodity Price Risk
We are exposed to the impact of fluctuations in the market price of oil, natural gas and NGLs, as well as other market factors, such as market volatility and energy commodity price correlations. We are exposed to these risks in connection with our owned energy-related assets, our long-term energy-related contracts and our marketing trading activities. We manage the risks associated with these market fluctuations using various derivatives and nonderivative energy-related contracts. The fair value of derivative contracts is subject to many factors, including changes in energy commodity market prices, the liquidity and volatility of the markets in which the contracts are transacted and changes in interest rates. We have previously disclosed the value-at-risk; however, a sensitivity analysis is predominately the disclosure used by our peers. See Notes 15 and 16 of Notes to Consolidated Financial Statements.
An assumed increase in forward prices used in the valuation of our crude oil and natural gas fixed price swap and option derivatives of $5.00 per Bbl and $0.25 per MMBtu would decrease our derivative valuation by approximately $165 million and $82 million at December 31, 2019 and December 31, 2018, respectively. Conversely, an assumed decrease in forward prices of $5.00 per Bbl and $0.25 per MMBtu would increase our derivative valuation by $151 million and $81 million at December 31, 2019 and December 31, 2018, respectively. However, any cash derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production economically hedged by the derivative instruments. Contracts designated as normal purchases or sales and nonderivative energy contracts have been excluded from this sensitivity analysis.
Our portfolio consists of derivative contracts that hedge or could potentially hedge the price risk exposure from our energy commodity purchases and sales. The fair value of our derivatives not designated as hedging instruments was a net liability of $24 million at December 31, 2019 and net asset of $141 million at December 31, 2018.
Item 8.
Item 8.Financial Statements and Supplementary Data
MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934). Our internal controls over financial reporting are designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of financial statements in accordance with accounting principles generally accepted in the United States. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management and Board of Directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.
All internal control systems, no matter how well designed, have inherent limitations including the possibility of human error and the circumvention or overriding of controls. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2019, based on the criteria set forth in 2013 by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control-Integrated Framework. Based on our assessment, we concluded that, as of December 31, 2019, our internal control over financial reporting was effective.
Ernst & Young LLP, our independent registered public accounting firm, has audited our internal control over financial reporting, as stated in their report which is included in this Annual Report on Form 10-K.
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors of WPX Energy, Inc.,
Opinion on Internal Control over Financial Reporting
We have audited WPX Energy, Inc.’s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, WPX Energy, Inc. (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of WPX Energy, Inc. as of December 31, 2019 and 2018, and the related consolidated statements of operations, changes in equity and cash flows for each of the three years in the period ended December 31, 2019, and the related notes and financial statement schedule listed in the Index at Item 15.(a) and our report dated February 27, 2020 expressed an unqualified opinion thereon.
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 Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We 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 included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and 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.
/s/ Ernst & Young LLP
Tulsa, Oklahoma
February 27, 2020
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors of WPX Energy, Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of WPX Energy, Inc. (the Company) as of December 31, 2019 and 2018, and the related consolidated statements of operations, changes in equity and cash flows for each of the three years in the period ended December 31, 2019, and the related notes and financial statement schedule listed in the Index at Item 15.(a) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Company at December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 27, 2020 expressed an unqualified opinion thereon.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Depreciation, Depletion, and Amortization (DD&A) of Proved Properties
Description of the Matter The net book value of proved properties totaled $5.9 billion at December 31, 2019, and the Company recorded depreciation, depletion and amortization (DD&A) expense of $928 million for the year then ended. As discussed in Note 1, under the successful efforts method of accounting, DD&A for proved properties is recorded on a field basis using the units-of-production method. Proved developed reserves, as estimated by the Company’s internal engineering staff, are used to calculate depreciation and amortization of capitalized exploratory and development drilling costs, including lease and well equipment and intangible development costs. Total proved reserves, also estimated by the Company’s internal engineering staff, are used to calculate depletion of producing leasehold costs. Significant judgment is required by the Company’s internal engineering staff in evaluating geological and engineering data when estimating proved oil and gas reserves. Estimating reserves also requires the selection of inputs, including oil and
gas price assumptions, future operating and capital costs assumptions, and tax rates by jurisdiction, among others. Because of the complexity involved in estimating oil and gas reserves, management used independent petroleum engineers to audit the estimates prepared by the Company’s internal engineering staff as of December 31, 2019.
Auditing the Company’s DD&A is especially complex because of the use of the work of the internal engineering staff and the independent petroleum engineers and the evaluation of management’s determination of the inputs described above used by the engineers in estimating proved oil and gas reserves.
How We Addressed the Matter in Our Audit We obtained an understanding, evaluated the design and tested the operating effectiveness of the Company’s controls over its process to calculate DD&A, including management’s controls over the completeness and accuracy of the financial data provided to the engineers for use in estimating proved oil and gas reserves.
Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the Company’s internal technical person primarily responsible for overseeing the preparation of the reserve estimates by the internal engineering staff and the independent petroleum engineers used to audit the estimates. In addition, in assessing whether we can use the work of the internal engineering staff and the independent petroleum engineers, we evaluated the completeness and accuracy of the financial data and inputs described above used by the engineers in estimating proved oil and gas reserves by agreeing them to source documentation and we identified and evaluated corroborative and contrary evidence. We also tested the mechanical accuracy of the DD&A calculations, including agreeing the proved oil and gas reserve amounts used to the Company’s reserve reports.
Amortization of Unproved Lease Acquisition Costs
Description of the Matter At December 31, 2019, unproved properties were $1.8 billion, which includes unproved lease acquisition costs. As discussed in Note 1 to the consolidated financial statements, lease acquisition costs that are not individually significant are aggregated by prospect or geographically, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. The amortization of lease acquisition costs is included in exploration expense on the Consolidated Statements of Operations.
Auditing the amortization of unproved leasehold acquisition costs was complex and judgmental due to the significant estimation required by management in determining the nonproductive portion of leasehold costs and the average holding period. The significant assumptions used to estimate the nonproductive portion of unproved lease acquisition costs included the Company’s historical experience or other information, such as current drilling plans and existing geological data.
How We Addressed the Matter in Our Audit We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s process for the amortization of unproved lease acquisition costs. For example, we tested controls over management’s review of the significant assumptions and inputs used in determining the amortization of unproved leasehold acquisition costs, including the estimated unsuccessful portion of unproved lease acquisition costs, and the estimated average holding period of unproved leases.
Our audit procedures included, among others, evaluating the significant assumptions and the completeness and accuracy of the underlying financial data used by the Company in determining the amortization of unproved lease acquisition costs. As part of our evaluation, we considered the consistency of the significant assumptions used by management to estimate the unsuccessful portion of unproved lease acquisition costs with historical drilling results and the Company’s drilling schedule, and identified and evaluated corroborative and contrary evidence. In addition, we assessed the estimated average holding period of unproved leases by comparing to the Company’s historical experience. We also tested the mechanical accuracy of the calculation of unproved lease acquisition costs.
/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2010.
Tulsa, Oklahoma
February 27, 2020
WPX Energy, Inc.
Consolidated Balance Sheets
See accompanying notes.
WPX Energy, Inc.
Consolidated Statements of Operations
See accompanying notes.
WPX Energy, Inc.
Consolidated Statements of Changes in Equity
See accompanying notes.
WPX Energy, Inc.
Consolidated Statements of Cash Flows
See accompanying notes.
WPX Energy, Inc.
Notes to Consolidated Financial Statements
Note 1. Description of Business, Basis of Presentation and Summary of Significant Accounting Policies
Description of Business
Operations of our company include oil, natural gas and NGL development and production primarily located in Texas, New Mexico and North Dakota. We specialize in development and production from tight-sands and shale formations in the Delaware and Williston Basins. Associated with our commodity production are sales and marketing activities, referred to as commodity management activities, which include oil and natural gas purchased from third-party working interest owners in operated wells and the management of various commodity contracts, such as transportation.
We had operations in the San Juan Basin, which were sold in 2017 and 2018, that are reported in discontinued operations as discussed below.
The consolidated businesses represented herein as WPX Energy, Inc. is also referred to as “WPX,” the “Company,” “we,” “us” or “our.”
Basis of Presentation and Summary of Significant Accounting Policies
Principles of consolidation
The consolidated financial statements include the accounts of our wholly and majority-owned subsidiaries and investments. Companies in which we own 20 percent to 50 percent of the voting common stock, or otherwise exercise significant influence over operating and financial policies of the Company, are accounted for under the equity method. All material intercompany transactions have been eliminated. The Company has no other elements of comprehensive income (loss) other than net income (loss).
Our continuing operations comprise a single business segment, which includes the development, production and commodity management activities of oil, natural gas and NGLs in the United States.
Discontinued Operations
See Note 2 for a further discussion of discontinued operations. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations.
Use of estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
Significant estimates and assumptions that impact these financials include:
•impairment assessments of long-lived assets;
•valuation of deferred tax assets and liabilities;
•valuations of derivatives;
•estimation of oil and natural gas reserves; and
•assessments of litigation-related contingencies.
These estimates are discussed further throughout these notes.
Cash and cash equivalents
Our cash and cash equivalents balance includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have maturity dates of three months or less when acquired.
Restricted cash
Restricted cash was approximately $20 million and $15 million as of December 31, 2019 and 2018, respectively, and is included in other current assets on the Consolidated Balance Sheets.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Accounts receivable
Accounts receivable are carried on a gross basis, with no discounting, less the allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial conditions of the customers and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. A portion of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.
Inventories
All inventories are stated at the lower of cost or market. Our materials, supplies and other inventories consist of tubular goods and production equipment for future transfer to wells and crude oil production in transit. Inventory is recorded and relieved using the weighted average cost method. The following table presents a summary of inventories.
Properties and equipment
Oil and gas exploration and production activities are accounted for under the successful efforts method. Costs incurred in connection with the drilling and equipping of exploratory wells are capitalized as incurred. If proved reserves are not found, such costs are charged to exploration expenses. Other exploration costs, including geological and geophysical costs and lease rentals are charged to expense as incurred. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred whether productive or nonproductive.
Unproved properties include lease acquisition costs. Individually significant lease acquisition costs are assessed annually, or as conditions warrant, for impairment considering our future drilling plans, the remaining lease term and recent drilling results. Lease acquisition costs that are not individually significant are aggregated by prospect or geographically, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. The estimate of what could be nonproductive is based on our historical experience or other information, including current drilling plans and existing geological data. Impairment and amortization of lease acquisition costs are included in exploration expense on the Consolidated Statements of Operations. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. We refer to unproved lease acquisition costs as unproved properties.
From time to time we may exchange leasehold acreage with third parties. In connection with this type of nonmonetary exchange in which commercial substance is established, we must record assets received based on the fair value of either the asset surrendered or, if more readily determinable, the assets received. Any resulting difference between the fair value and the carrying value of the assets is recorded as a gain or loss, to the extent a loss exceeds accumulated amortization, in the Consolidated Statements of Operations.
Gains or losses from the ordinary sale or retirement of properties and equipment are recorded in operating income (loss) as either a separate line item, if individually significant, or included in other-net on the Consolidated Statements of Operations.
Costs related to the construction or acquisition of field gathering, processing and certain other facilities are recorded at cost. Ordinary maintenance and repair costs are expensed as incurred.
Depreciation, depletion and amortization
Capitalized exploratory and developmental drilling costs, including lease and well equipment and intangible development costs are depreciated and amortized using the units-of-production method based on estimated proved developed oil and gas reserves on a field basis. Depletion of producing leasehold costs is based on the units-of-production method using estimated total proved oil and gas reserves on a field basis. In arriving at rates under the units-of-production methodology, the quantities of proved oil and gas reserves are established based on estimates made by our geologists and engineers.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Costs related to gathering, processing and certain other facilities are depreciated on the straight-line method over the estimated useful lives.
Impairment of long-lived assets
We evaluate our long-lived assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.
Proved properties, including developed and undeveloped, are assessed for impairment using estimated future undiscounted cash flows on a field basis. If the undiscounted cash flows are less than the book value of the assets, then a subsequent analysis is performed using discounted cash flows. Additionally, our leasehold costs are evaluated for impairment if the proved property costs within a basin are impaired.
Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s fair value. These judgments and assumptions include such matters as the estimation of oil and gas reserve quantities, risks associated with the different categories of oil and gas reserves, the timing of development and production, expected future commodity prices, capital expenditures, production costs, and appropriate discount rates.
Contingent liabilities
Due to the nature of our business, we are routinely subject to various lawsuits, claims and other proceedings. We recognize a liability in our consolidated financial statements when we determine that it is probable that a loss has been incurred and the amount can be reasonably estimated. If we determine that a loss is probable but lack information on which to reasonably estimate a loss, if any, or if we determine that a loss is only reasonably possible, we do not recognize a liability. We disclose the nature of loss contingencies that are potentially material but for which no liability has been recognized.
Asset retirement obligations
We record an asset and a liability upon incurrence equal to the present value of each expected future asset retirement obligation (“ARO”). These estimates include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market risk premium. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense in lease and facility operating expense included in costs and expenses.
Cash flows from revolving credit facilities
Proceeds and payments related to any borrowings under a revolving credit facility are reflected in the financing activities of the Consolidated Statements of Cash Flows on a gross basis.
Derivative instruments and hedging activities
We utilize derivatives to manage our commodity price risk. These instruments consist primarily of futures contracts, swap agreements, option contracts, and forward contracts involving short- and long-term purchases and sales of a physical energy commodity.
We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, on the Consolidated Balance Sheets in derivative assets and derivative liabilities as either current or noncurrent. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
The accounting for the changes in fair value of a commodity derivative can be summarized as follows:
Derivative Treatment Accounting Method
Normal purchases and normal sales exception Accrual accounting
Designated in a qualifying hedging relationship Hedge accounting
All other derivatives Mark-to-market accounting
We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of a physical energy commodity. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.
Certain gains and losses on derivative instruments included on the Consolidated Statements of Operations are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include:
•unrealized gains and losses on all derivatives that are not designated as cash flow hedges related to production and for which we have not elected the normal purchases and normal sales exception;
•unrealized gains and losses on all derivatives that are not designated as cash flow hedges related to commodity management and for which we have not elected the normal purchases and normal sales exception;
•realized gains and losses on all derivatives that settle financially;
•realized gains and losses on derivatives held for trading purposes; and
•realized gains and losses on derivatives entered into as a pre-contemplated buy/sell arrangement.
Realized gains and losses on derivatives that require physical delivery are recorded on a gross basis. In reaching our conclusions on this presentation, we considered whether we act as principal in the transaction; whether we have the risks and rewards of ownership, including credit risk; and whether we have latitude in establishing prices.
Product and commodity management revenues
Our revenues on the Consolidated Statement of Operations include oil, natural gas and natural gas liquids sales (collectively, “product revenues”), commodity management revenues and net gain (loss) on derivatives. Product revenues relate to production from properties in which we own an interest. Commodity management revenues primarily relate to sales of products we may purchase from other third parties in the areas we operate. We derive substantially all of our revenues from the sale of oil, natural gas and natural gas liquids in the continental United States. We believe the disaggregation of product revenues into the three major product types of oil sales, natural gas sales and natural gas liquid sales is an appropriate level of detail for our company’s primary activity and industry.
Our contracts for oil and natural gas sales are typically standard industry contracts that may include modifications for counterparty-specific provisions related to volumes, price differentials, discounts and other adjustments and deductions. Our contracts related to natural gas liquids sales are generally with the company contracted to gather and process natural gas to extract the natural gas liquids. The provider of these services typically purchases our share of the natural gas liquids pursuant to the terms of each contract. Oil, natural gas and natural gas liquids prices are derived from stated market prices which are then adjusted to reflect deductions including fuel, shrink, transportation, fractionation and processing. Product revenues are initially accrued based on volume and price estimates using the best available information. These accruals are typically actualized one to two months later when volume and pricing are confirmed. Adjustments to actualize the accruals for product revenues are generally not material.
Revenue is recognized when the performance obligations under the terms of our contracts with customers are satisfied. The primary performance obligation for the material portion of our revenue contracts is the delivery of oil, natural gas or natural gas liquids to our customers. Significant judgments related to revenue recognition include principal versus agent considerations.
We record revenue on a gross basis when we control a promised good or service before transferring it to a customer. We record revenue on a net basis when we arrange for another company to provide the good or service. Determining the point and time when control of a product transfers to a customer requires significant judgment. Payment is typically due 30 to 45 days following delivery of product to our customers.
Revenues from production in properties for which we have an interest with other producers are recognized based on the actual volumes sold during the period. Any differences between volumes sold and entitlement volumes, based on our net revenue interest, that are determined to be nonrecoverable through remaining production are recognized as accounts receivable
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Notes to Consolidated Financial Statements-(Continued)
or accounts payable, as appropriate. Our cumulative net oil and natural gas imbalance position based on market prices as of December 31, 2019 and 2018 was insignificant.
Commodity management expenses
Commodity management expenses primarily relate to product we may purchase from other third parties in the areas we operate.
Income taxes
We file consolidated and combined federal and state income tax returns for the Company and its subsidiaries. We record deferred taxes for the differences between the tax and book basis of our assets as well as loss or credit carryovers to future years. A valuation allowance is established to reduce deferred tax assets if it is determined it is more likely than not that the related tax benefit will not be realized. Deferred tax liabilities and assets are classified as noncurrent on the statement of financial position.
Employee stock-based compensation
Restricted stock units and awards are generally valued at market value on the grant date and generally vest over three years. Restricted stock compensation cost, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis. Performance-based awards are tied to shareholder return over time relative to our peer group and are valued using a Monte Carlo method using measures of total shareholder return.
Earnings (loss) per common share
Basic earnings (loss) per common share is based on the sum of the weighted-average number of common shares outstanding and vested restricted stock units. Diluted earnings (loss) per common share includes any dilutive effect of stock options and nonvested restricted stock units and awards (see Note 3).
Debt issuance costs
Debt issuance fees, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods. The Company had total net debt issuance costs of $36 million and $35 million as of December 31, 2019 and 2018, respectively. Unamortized debt issuance costs related to the Company’s senior unsecured notes are reported in long-term debt (see Note 8) and debt issuance costs related to the Credit Facility are recorded in other noncurrent assets on the Company’s Consolidated Balance Sheets.
Recently Adopted Accounting Standards
The Company adopted Accounting Standards Update (“ASU”) 2016-02, Leases, effective January 1, 2019. The standard requires the recognition of right-of-use assets and lease liabilities on the balance sheet and disclosure of key information about leasing arrangements. Under the new standard, a determination is made at the inception of a contract as to whether the contract is, or contains a lease. Leases convey the right to control the use of an identified asset in exchange for consideration. We used a transition method that applies the new lease standard at January 1, 2019, and recognizes any cumulative-effect adjustments to the opening balance of 2019 retained earnings. The cumulative effect adjustment was not material. Upon adoption, we recorded initial right-of-use assets of $90 million in other noncurrent assets, noncurrent lease liabilities of $46 million in other noncurrent liabilities and current lease liabilities of $44 million in accrued and other current liabilities. The Company applied a policy election to exclude short-term leases (leases with a term of 12 months or less) from balance sheet recognition and also elected certain practical expedients at adoption including the treatment of lease and non-lease components as a single lease component for all asset classes. As permitted, we applied certain other practical expedients in which we elected not to reassess:
•whether existing contracts are or contain leases;
•lease classification for any expired or existing leases;
•initial direct costs for any existing lease; and
•whether existing land easements and rights of way, that were not previously accounted for as leases, are or contain a lease.
See Note 11 for additional information related to our contracts that are or contain leases.
We adopted ASU 2017-12, Derivatives and Hedging (Topic 815) effective January 1, 2019. This ASU provides guidance for various components of hedge accounting including hedge ineffectiveness, the expansion of types of permissible hedging strategies, reduced complexity in the application of the long-haul method for fair value hedges and reduced complexity in
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assessment of effectiveness. The adoption of this standard did not have a significant impact on the Company. However, we would be impacted if we were to apply hedge accounting in a future period.
Accounting Standards Not Yet Adopted
In June 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-13, Financial Instruments - Credit Losses. This ASU, as further amended, affects trade receivables, financial assets and certain other instruments that are not measured at fair value through net income. This ASU will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost and is effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This ASU will be applied using a modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Company does not believe the adoption of this ASU will have a material impact on the Company’s consolidated financial statements since the Company does not have a history of material credit losses.
In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement. This ASU eliminates, adds and modifies certain disclosure requirements for fair value measurements. Entities will no longer be required to disclose the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, but public companies will be required to disclose additional information about significant unobservable inputs for Level 3 measurements. The amendments in this ASU are effective for public entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2019. The Company does not expect any significant impact on its consolidated financial statements from the adoption of this standard.
Note 2. Discontinued Operations
In first-quarter 2018, we sold our properties in the San Juan Basin’s Gallup oil play and we received approximately $667 million (subject to post-closing adjustments). In addition, the purchaser assumed approximately $309 million of annual gathering and processing commitments that conclude in 2026; however, WPX has left in place a performance guarantee with respect to these commitments. The current remaining commitment is approximately $277 million. We believed and continue to believe that any future performance under this guarantee obligation is highly unlikely given our understanding of the buyer’s credit position, the indemnity arrangement between the Company and the purchaser, and the declining size of the obligations subject to the guarantee over time. As part of the divestiture, we determined the fair value of the guarantee that was provided. We estimated the fair value of the guarantee to be approximately $9 million based on the factors mentioned above along with projections of estimated future volume throughputs and risk adjusted discount rates, all of which are Level 3 inputs. This amount is included in our calculation of the loss on sale. We recorded a total loss on the sale of $147 million in 2018.
In December 2017, we sold our natural gas-producing properties in the San Juan Basin for $169 million and recorded a gain of approximately $2 million. A portion of this sale closed in 2018.
Our discontinued operations consist of the previously owned properties in the San Juan Basin and accretion on certain transportation and gathering obligations retained and recognized in prior years related to the sale of Powder River properties. See Note 10 for additional information related to the Powder River liabilities.
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Notes to Consolidated Financial Statements-(Continued)
Summarized Results of Discontinued Operations
The following table presents the results of discontinued operations for the years presented. For the year ended December 31, 2019, our discontinued operations activity was minimal and therefore not included in the table below.
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(a) Includes severance tax refund received in 2017.
Cash Flows Attributable to Discontinued Operations
In addition to the amounts presented below, cash outflows related to previous accruals for the Powder River Basin gathering and transportation contracts retained by WPX were $28 million, $47 million and $53 million for 2019, 2018 and 2017, respectively. During 2017, we received a $10 million severance tax refund for prior years related to our former Piceance Basin operations.
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(a) Excluding income taxes and changes to working capital.
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Notes to Consolidated Financial Statements-(Continued)
Note 3. Earnings (Loss) Per Common Share from Continuing Operations
The following table summarizes the calculation of earnings per share.
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(a) Certain amounts are excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to (i) application of the if-converted method to common shares issuable upon assumed conversion of convertible preferred stock; or (ii) application of the treasury stock method to certain nonvested restricted stock units. The remaining Series A mandatory convertible preferred stock converted to common shares in third-quarter 2018. The excluded amounts are as follows:
The table below includes information related to stock options that were outstanding at December 31, 2019, 2018 and 2017 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the fourth quarter weighted-average market price of our common shares.
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Notes to Consolidated Financial Statements-(Continued)
Note 4. Asset Sales, Exploration Expenses and Other
Asset Sales
During the first quarter of 2019, we closed on the sale of certain non-core properties, primarily proved, in the Delaware Basin which were held for sale at December 31, 2018. We received approximately $83 million in proceeds. No gain or loss was recorded on this transaction.
Net gain on sales of assets for the year ended December 31, 2017 primarily reflect total gains of $103 million from exchanges of leasehold acreage in the Permian Basin, $48 million from the recognition of deferred gains related to the completion of commitments from the sale in 2015 of a North Dakota gathering system and $8 million recognized on the sales of certain Green River Basin and Appalachian Basin assets.
In conjunction with exchanges of leasehold, we estimated the fair value of the leasehold through discounted cash flow models and consideration of market data. Our estimates and assumptions included future commodity prices, projection of estimated quantities of oil and natural gas reserves, expectations for future development and operating costs and risk adjusted discount rates, all of which are Level 3 inputs.
Exploration Expenses
The following table presents a summary of exploration expenses.
Unproved leasehold property impairment, amortization and expiration for 2017 includes costs in excess of the accumulated amortization balance associated with certain leases in the Permian Basin that expired during the first quarter of 2017. These leases were renewed in second-quarter 2017.
Other
In third-quarter 2019, we recorded an $11 million charge included in other-net on the Consolidated Statements of Operations associated with an offer made by us to settle certain contractual disputes in the Williston Basin. The offer is still pending.
Note 5. Investments
Catalyst Midstream Partners, LLC
In June 2017, we signed an agreement with Howard Energy Partners (“Howard”) to jointly develop oil gathering and natural gas processing infrastructure in the Stateline area of the Delaware Basin. Under the terms of the agreement, WPX and Howard each have a 50 percent voting interest in the joint venture legal entity, Catalyst Midstream Partners LLC (“Catalyst”) and a Howard entity serves as operator. We account for our investment in Catalyst as an equity method investment. In connection with the joint venture formation, a consolidated subsidiary of WPX dedicated production from its current and future leasehold interest in the Stateline area, representing 50,000 net acres in the Delaware Basin, pursuant to 20 year fixed-fee oil gathering and natural gas processing agreements with subsidiaries of Catalyst. The agreements do not include any minimum volume commitments. Our investment in Catalyst totaled $48 million and $58 million as of December 31, 2019 and 2018, respectively. As of December 31, 2019, the difference in our investment and our underlying equity in the net assets of Catalyst was approximately $244 million. In 2017, we deferred recognition of the $349 million we received at closing and will recognize it over the 20 years based on production volumes as a deduction to gathering, processing and transportation expense. As of December 31, 2019, the deferred amount was $339 million of which $329 million is reported within other noncurrent liabilities on the Consolidated Balance Sheet.
Other
During 2018, we contributed an additional $93 million to our equity method investment in the Oryx II pipeline project, of which $23 million increased our ownership from 12.5 percent to 25 percent. During the second quarter of 2019, we received a distribution of approximately $357 million related to our 25 percent equity interest in the Oryx pipeline partnership after the
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underlying assets were sold. This transaction is subject to post-closing adjustments. The net book value of this equity method investment was approximately $110 million as of the closing date. As a result of this transaction, we recorded a gain of $247 million.
During the first quarter of 2019, we closed on the sale of our 20 percent equity interest in the Whitewater natural gas pipeline. The net book value of this equity method investment at the time of disposition was approximately $15 million. As a result of this transaction, we recorded a $126 million gain in first-quarter 2019 and an additional $7 million gain related to contingent consideration in fourth-quarter 2019.
Note 6. Properties and Equipment
Properties and equipment is carried at cost and consists of the following:
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(a) Estimated useful lives are presented as of December 31, 2019.
(b) Proved properties are depreciated, depleted and amortized using the units-of-production method (see Note 1).
(c) Unproved properties, land and construction in progress are not subject to depreciation and depletion.
Unproved properties consist primarily of non-producing leasehold in the Delaware Basin.
In first-quarter 2019, we closed a $100 million purchase of 14,000 surface acres within our Stateline operations of which a portion was allocated to unproved properties and the remainder to land.
In December 2018, we signed an agreement to sell certain non-core properties in the Delaware Basin, which closed in the first quarter of 2019. These properties are reflected in assets classified as held for sale on the Consolidated Balance Sheet for December 31, 2018 (see Note 4).
Asset Retirement Obligations
Our asset retirement obligations relate to producing wells, gathering well connections and related facilities. At the end of the useful life of each respective asset, we are legally obligated to plug producing wells and remove any related surface equipment and to cap gathering well connections at the wellhead and remove any related facility surface equipment. Asset retirement obligations are reported in other noncurrent liabilities on the Consolidated Balance Sheets.
A rollforward of our asset retirement obligations for the years ended 2019 and 2018 is presented below.
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(a) Accretion expense is included in lease and facility operating expense on the Consolidated Statements of Operations.
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Notes to Consolidated Financial Statements-(Continued)
Note 7. Accounts Payable and Accrued and Other Current Liabilities
Accounts Payable
The following table presents a summary of our accounts payable as of the dates indicated below.
Accrued and other current liabilities
The following table presents a summary of our accrued and other current liabilities as of the dates indicated below.
Note 8. Debt and Banking Arrangements
Interest paid on debt totaled $150 million, $172 million and $178 million for 2019, 2018 and 2017, respectively.
The following table presents a summary of our debt as of the dates indicated below.
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(a) Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets.
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Notes to Consolidated Financial Statements-(Continued)
Credit Facility
On April 22, 2019, the Company entered into a Third Amendment to Second Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as Administrative Agent, Lender and Swingline Lender and the other lenders party thereto (the “Credit Facility”). The Credit Facility, as amended, gives the Company the option, if certain conditions are met, to elect during any Collateral Trigger Period that scheduled redeterminations of the Borrowing Base be made annually on April 1 instead of semi-annually.
Based on our current credit ratings, a Collateral Trigger Period applies that makes the Credit Facility subject to certain financial covenants and a Borrowing Base as described below. The Credit Facility may be used for working capital, acquisitions, capital expenditures and other general corporate purposes. The financial covenants in the Credit Facility may limit our ability to borrow money, depending on the applicable financial metrics at any given time. As of December 31, 2019, WPX had no borrowings outstanding, had $28 million of letters of credit issued under the Credit Facility and was in compliance with our covenants under the Credit Facility.
Borrowing Base. During a Collateral Trigger Period, loans under the Credit Facility are subject to a Borrowing Base as calculated in accordance with the provisions of the Credit Facility. In April 2019, the Borrowing Base was increased to $2.1 billion and will remain in effect until the next Redetermination Date as described above. At this time, the Credit Facility Agreement is limited by the total commitments which remained at $1.5 billion.
Terms and Conditions. The Credit Facility is guaranteed by certain subsidiaries of the Company (excluding subsidiaries holding Midstream Assets and subsidiaries meeting other customary exclusion criteria), as Guarantors, and secured by substantially all of the Company’s and the Guarantors’ assets (including oil and gas properties), subject to customary exceptions and carve outs (which shall also exclude Midstream Assets and the equity interests of subsidiaries holding Midstream Assets). Such guarantees shall terminate on the earlier of any applicable Collateral Trigger Termination Date (as described below) or the date on which all liens held by the Administrative Agent for the benefit of the secured parties are released pursuant to the terms of the Credit Facility.
The Collateral Trigger Termination Date is the first date following the Second Amendment Effective Date and the first date following any Collateral Trigger Date, as applicable, on which:
1.(i) the Company’s Corporate Rating is BBB- or better by S&P (without negative outlook or negative watch) or (ii) Baa3 or better by Moody’s (without negative outlook or negative watch), provided that the other of the two Corporate Ratings is at least BB+ by S&P or Ba1 by Moody’s; or
2.in the case of a Voluntary Collateral Trigger Period, WPX elects to cause a Collateral Trigger Termination Date to occur.
Interest and Commitment Fees. Interest on borrowings under the Credit Facility is payable at rates per annum equal to, at the Company’s option: (1) a fluctuating base rate equal to the alternate base rate plus the applicable margin, or (2) a periodic fixed rate equal to LIBOR plus the applicable margin. The alternate base rate will be the highest of (i) the federal funds rate plus 0.5 percent, (ii) the Prime Rate, and (iii) one-month LIBOR plus 1.0 percent. The Company is required to pay a commitment fee based on the unused portion of the commitments under the Credit Facility. The applicable margin and the commitment fees during a Collateral Trigger Period are determined by reference to a utilization percentage as set forth in the Credit Facility. The applicable margin and the commitment fee other than during a Collateral Trigger Period are determined by reference to a pricing schedule based on the Company’s senior unsecured non-credit enhanced debt ratings.
Significant Financial Covenants.
Currently, the Company is required to maintain:
• ratio of Consolidated Net Indebtedness to Consolidated EBITDAX (for the most recently ended four consecutive fiscal quarters) of not greater than 4.25 to 1.00 as of the last day of the Rolling Period; and
•a ratio of consolidated current assets (including the unused amount of the Borrowing Base) of the Company and its consolidated subsidiaries to the consolidated current liabilities of the Company and its consolidated subsidiaries as of the last day of any fiscal quarter of at least 1.0 to 1.0.
If a Collateral Trigger Termination Date occurs, other financial covenants would apply.
Covenants. The Credit Facility contains customary representations and warranties and affirmative, negative and financial covenants (as described above), which were made only for the purposes of the Credit Facility and as of the specific date (or dates) set forth therein, and may be subject to certain limitations as agreed upon by the contracting parties. The covenants limit, among other things, the ability of the Company’s subsidiaries to incur indebtedness; the ability of the Company
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Notes to Consolidated Financial Statements-(Continued)
and its subsidiaries to grant certain liens, make restricted payments, materially change the nature of its or their business, make investments, guarantees, loans or advances in non-subsidiaries or enter into certain hedging agreements; the ability of the Company’s material subsidiaries to enter into certain restrictive agreements; the ability of the Company and its material subsidiaries to enter into certain affiliate transactions; the ability of the Company and its subsidiaries to redeem any senior notes; and the Company’s ability to merge or consolidate with any person or sell all or substantially all of its assets to any person. The Company and its subsidiaries are also prohibited from using the proceeds under the Credit Facility in violation of Sanctions (as defined in the Credit Facility). In addition, the representations, warranties and covenants contained in the Credit Facility are subject to certain exceptions and/or standards of materiality applicable to the contracting parties.
Events of Default. The Credit Facility includes customary events of default, including events of default relating to:
•non-payment of principal, interest or fees;
•inaccuracy of representations and warranties in any material respect when made or when deemed made;
•violation of covenants;
•cross payment-defaults;
•cross acceleration;
•bankruptcy and insolvency events;
•certain unsatisfied judgments;
•a change of control; and
•during any secured period, the failure of the collateral documents to be in effect or a lien to be valid and perfected.
If an event of default with respect to a borrower occurs under the Credit Facility, the lenders will be able to terminate the commitments and accelerate the maturity of the loans of the defaulting borrower under the Credit Facility and exercise other rights and remedies.
Senior Notes
The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding unsecured senior note obligations at December 31, 2019.
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(a) At any time prior to these dates, we have the option to redeem some or all of the notes at a specified “make whole” premium as described in the indenture(s) governing the notes to be redeemed. On or after these dates, we have the option to redeem the notes, in whole or in part, at the applicable redemption prices set forth in the indenture, plus accrued and unpaid interest thereon to the redemption date as more fully described in the indenture.
See Note 17 for a discussion of Senior Notes issued subsequent to December 31, 2019.
On September 24, 2019, we completed a debt offering of $600 million of 5.250% Senior Notes due in 2027 (the “2027 Notes”). The notes are senior unsecured obligations ranking equally with the Company’s other existing and future senior unsecured indebtedness. Interest is payable on the notes semiannually in arrears on April 15 and October 15 of each year commencing on April 15, 2020. The 2027 Notes will mature on October 15, 2027 with the option, prior to October 15, 2022, to redeem some or all of the notes at a specified “make whole” premium as described in the indenture governing the notes or, at any time on or after October 15, 2022, we have the option to redeem the notes, in whole or in part, at the applicable redemption
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prices set forth in the indenture. The net proceeds from the offering of the 2027 Notes was approximately $592.5 million and approximately $2 million of debt issuance costs were capitalized.
The net proceeds from this offering were used to fund the purchase of $550 million aggregate principal amount of our 2022 Notes and 2023 Notes through cash tender offers. As a result of the debt tender offers, we recorded a loss on extinguishment of debt of $47 million, which includes approximately $44 million of premium and approximately $3 million write-off of previously capitalized costs.
In the second quarter of 2018, we used proceeds from our San Juan Gallup disposition and the issuance of new senior notes discussed below to retire $921 million aggregate principal amount of our senior notes ($350 million due 2020 and $571 million due 2022) through a series of cash tender offers. As a result of the debt tender offers, we recorded a loss on extinguishment of debt of $71 million, which includes approximately $63 million of premium and approximately $6 million write-off of previously capitalized costs.
On May 23, 2018, we completed a debt offering of $500 million of 5.750% Senior Notes due in 2026 (the “2026 Notes”). The notes are senior unsecured obligations ranking equally with the Company’s other existing and future senior unsecured indebtedness. Interest is payable on the notes semiannually in arrears on June 1 and December 1 of each year commencing on December 1, 2018. The 2026 Notes will mature on June 1, 2026 with the option, prior to June 1, 2021, to redeem some or all of the notes at a specified “make whole” premium as described in the indenture governing the notes or, after June 1, 2021, we have the option to redeem the notes, in whole or in part, at the applicable redemption prices set forth in the indenture. The net proceeds from the offering of the 2026 Notes was approximately $494 million and approximately $1 million of debt issuance costs were capitalized.
The terms of the indentures governing our 2022 Notes, 2023 Notes, 2024 Notes, 2026 Notes and 2027 Notes are substantially identical.
Change of Control. If we experience a change of control (as defined in the indentures governing the notes) accompanied by a specified rating decline, we must offer to repurchase the notes of such series at 101% of their principal amount, plus accrued and unpaid interest.
Covenants. The terms of the indentures governing our notes restrict our ability and the ability of our subsidiaries to incur additional indebtedness secured by liens and to effect a consolidation, merger or sale of substantially all our assets. The indentures also require us to file with the trustee and the SEC certain documents and reports within certain time limits set forth in the indentures. However, these limitations and requirements are subject to a number of important qualifications and exceptions. The indentures do not require the maintenance of any financial ratios or specified levels of net worth or liquidity.
Events of Default. Each of the following is an “Event of Default” under the indentures with respect to the notes of any series:
(1) a default in the payment of interest on the notes when due that continues for 30 days;
(2) a default in the payment of the principal of or any premium, if any, on the notes when due at their stated maturity,
upon redemption, or otherwise;
(3) failure by us to duly observe or perform any other of the covenants or agreements (other than those described in
clause (1) or (2) above) in the indenture, which failure continues for a period of 60 days, or, in the case of the reporting covenant under the indenture, which failure continues for a period of 90 days, after the date on which written notice of such failure has been given to us by the trustee; provided, however, that if such failure is not capable of cure within such 60-day or 90-day period, as the case may be, such 60-day or 90-day period, as the case may be, will be automatically extended by an additional 60 days so long as (i) such failure is subject to cure and (ii) we are using commercially reasonable efforts to cure such failure; and
(4) certain events of bankruptcy, insolvency or reorganization described in the indenture.
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Notes to Consolidated Financial Statements-(Continued)
Note 9. Provision (Benefit) for Income Taxes
The following table includes the provision (benefit) for income taxes from continuing operations.
On December 22, 2017, the President of the United States signed into law the Tax Cuts and Jobs Act (“Act”). The income tax effects of changes in tax laws are recognized in the period when enacted. The Act lowered the corporate regular tax rate. The Act also repealed the corporate alternative minimum tax (“AMT”) and amended Section 53 of the Internal Revenue Code to allow for refunds of AMT credit carryforwards. Under Section 53(e), taxpayers receive 50 percent of their uncredited balance in years 2018-2020. Taxpayers receive 100 percent of the remaining balance in 2021. Accordingly, the Company had current receivables of $19 million and $38 million as of December 31, 2019 and 2018, respectively, related to AMT credit carryforward refunds. In 2019, we received the $38 million and expect the $19 million to be collected in 2020. However, our AMT credit carryforwards are subject to change based on the results of the 2011 Williams audit discussed below and may impact future refunds and those already received.
The following table provides reconciliations from the provision (benefit) for income taxes from continuing operations at the federal statutory rate to the realized provision (benefit) for income taxes.
As discussed below, we record a valuation allowance on certain state net operating loss (“NOL”) carryovers generated in current years.
Significant changes to our operations during 2019, 2018 and 2017 resulted in changes to our anticipated future state apportionment for our estimated state deferred tax liability. As a result of these changes and the differing state tax rates, we recorded an additional $10 million, $5 million and $12 million deferred tax benefit in 2019, 2018 and 2017, respectively.
Due to the uncertainty or diversity in views about the application of ASC 740 in the period of enactment of the Act, the SEC issued Staff Accounting Bulletin (“SAB”) 118 which allowed us to provide a provisional estimate of the impacts of the Act in our earnings for the year ending December 31, 2017. Additional impacts from the enactment of the Act were allowed to
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be recorded as they were identified during the one-year measurement period as provided for in SAB 118. However, the Company did not have any adjustments to its provisional amounts.
The following table includes significant components of deferred tax liabilities and deferred tax assets.
Net cash payments (receipts) for income taxes, including AMT credit carryforward refunds, were $(38) million, $2 million and $(39) million in 2019, 2018 and 2017, respectively.
The Company has federal NOL carryovers of approximately $2.1 billion at December 31, 2019, including a $218 million NOL acquired in 2015 ("RKI NOL"), that will not begin to expire until 2032. In addition, the Company has federal excess business interest expense carryover of approximately $20 million. The Company's $48 million federal capital loss carryovers have been utilized due to current year divestments.
The Company has state NOL carryovers of approximately $4.2 billion and $4.1 billion at 2019 and 2018, respectively, of which more than 99 percent expire after 2029.
We have recorded valuation allowances against deferred tax assets attributable primarily to certain state NOL carryovers. When assessing the need for a valuation allowance, we primarily consider future reversals of existing taxable temporary differences. To a lesser extent we may also consider future taxable income exclusive of reversing temporary differences and carryovers, and tax-planning strategies that would, if necessary, be implemented to accelerate taxable amounts to utilize expiring carryovers. The ultimate amount of deferred tax assets realized could be materially different from those recorded, as influenced by future operational performance, potential changes in jurisdictional income tax laws and other circumstances surrounding the actual realization of related tax assets. Valuation allowances that we have recorded are due to our expectation that we will not have sufficient income, or income of a sufficient character, in those jurisdictions to which the associated deferred tax asset applies. As of December 31, 2019, our assessment of federal net operating loss carryovers was that no valuation allowance was required; however, a future pretax loss may result in the need for a valuation allowance on our deferred tax assets.
The ability of WPX to utilize loss carryovers to reduce future federal taxable income and income tax could be subject to limitations under the Internal Revenue Code. The utilization of such carryovers may be limited upon the occurrence of certain ownership changes during any three year period resulting in an aggregate change of more than 50 percent in beneficial ownership (an “Ownership Change”). As of December 31, 2019, we do not believe that an Ownership Change has occurred for WPX, but an Ownership Change did occur for the company we acquired in 2015. Therefore, there is an annual limitation on the benefit that WPX can claim from RKI NOL that arose prior to the acquisition.
Pursuant to our tax sharing agreement with The Williams Companies ("Williams"), we remain responsible for the tax from audit adjustments related to our business for periods prior to our spin-off from Williams on December 31, 2011. The 2011 consolidated tax filing by Williams is currently being audited by the IRS and is the only pre spin-off period for which we continue to have exposure to audit adjustments as part of Williams. The IRS has proposed an adjustment related to our business for which a payment to Williams could be required. We have evaluated the issue and are in the process of protesting the adjustment within the normal Appeals process of the IRS. In addition, the AMT credit carryforward deferred tax asset that was
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Notes to Consolidated Financial Statements-(Continued)
allocated to us by Williams at the time of the spin-off could change due to audit adjustments unrelated to our business. Any such adjustments to this allocated deferred tax asset will not be known until the IRS examination is completed but is not expected to result in a cash settlement with Williams. However, if the Company has to amend filed returns whereby refunds of AMT credit carryforwards have been received, the Company may have to remit cash to the IRS. Through December 31, 2019, we have received approximately $50 million related to these AMT credit carryforwards.
The Company files a consolidated federal income tax return and several state income tax returns. The Company’s federal income tax returns for tax years 2014 through 2018 remain open for examination. The statute of limitations for most states expires one year after expiration of the IRS statute. During the year ended December 31, 2017, the IRS began an examination of the Company’s 2014, 2015 and 2016 federal income tax returns. In addition, the IRS began an examination of RKI’s 2014 and short-period 2015 federal income tax returns. These examinations remain ongoing and no additional taxes or refunds have been recorded at this time.
The Company’s policy is to recognize related interest and penalties as a component of income tax expense. The amounts accrued for interest and penalties are approximately $1 million or less for 2019, 2018 and 2017. The impact of this accrual is included within Other in our reconciliation of the provision (benefit) at statutory rate to recorded provision (benefit) for income taxes.
As of December 31, 2019, the Company has approximately $9 million of unrecognized tax benefits, which is offset by an increase in deferred tax assets of approximately $7 million. During the next 12 months, we do not expect ultimate resolution of any uncertain tax position that would result in a significant increase or decrease of an unrecognized tax benefit.
Note 10. Contingent Liabilities and Commitments
Contingent Liabilities
Federal gas royalties
Other producers have been pursuing administrative appeals with a federal regulatory agency and have been in discussions with a state agency in New Mexico regarding certain deductions, comprised primarily of processing, treating and transportation costs, used in the calculation of royalties. Although we are not a party to those matters, we are monitoring them to evaluate whether their resolution might have the potential for unfavorable impact on our results of operations. Certain outstanding issues in those matters could be material to us. We received notice from the U.S. Department of Interior Office of Natural Resources Revenue (“ONRR”) in the fourth quarter of 2010, intending to clarify the guidelines for calculating federal royalties on conventional gas production applicable to many of our federal leases in New Mexico. The guidelines for New Mexico properties were revised slightly in September 2013 as a result of additional work performed by the ONRR. The revisions did not change the basic function of the original guidance. The ONRR’s guidance provides its view as to how much of a producer’s bundled fees for transportation and processing can be deducted from the royalty payment. We believe using these guidelines would not result in a material difference in determining our historical federal royalty payments for our leases in New Mexico. Similar guidelines were subsequently issued for certain leases in Colorado and, as in the case of the New Mexico guidelines, we do not believe that they will result in a material difference to our historical federal royalty payments. ONRR has asked producers to attempt to evaluate the deductibility of these fees directly with the midstream companies that transport and process gas.
Environmental matters
The EPA, other federal agencies, and various state and local regulatory agencies and jurisdictions routinely promulgate and propose new rules, and issue updated guidance to existing rules. These new rules and rulemakings include, but are not limited to, new air quality standards for ground level ozone, methane, green completions, and hydraulic fracturing and water standards. We are unable to estimate the costs of asset additions or modifications necessary to comply with these new regulations due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.
Matters related to Williams’ former power business
In connection with a Separation and Distribution Agreement between WPX and Williams, Williams is obligated to indemnify and hold us harmless from any losses arising out of liabilities assumed by us for the pending litigation described below relating to the reporting of certain natural gas-related information to trade publications.
Civil suits based on allegations of manipulating published gas price indices have been brought against us and others, seeking unspecified amounts of damages. We are currently a defendant in class action litigation and other litigation originally filed in state court in Colorado, Kansas, Missouri and Wisconsin and brought on behalf of direct and indirect purchasers of natural gas in those states. These cases were transferred to the federal court in Nevada. In 2008, the court granted summary
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Notes to Consolidated Financial Statements-(Continued)
judgment in the Colorado case in favor of us and most of the other defendants based on plaintiffs’ lack of standing. On January 8, 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal and entered judgment in our favor. On August 6, 2018, the Ninth Circuit reversed the orders denying class certification and remanded to the MDL Court. On September 7, 2018, those plaintiffs filed a motion seeking remand to the originally filed district courts of Missouri, Kansas and Wisconsin. In February, 2019, settlement agreements with the Kansas and Missouri class claimants were executed, and on August 5, 2019, after the final fairness hearing, the court approved the settlement and entered final judgment. In the Wisconsin putative class action, the case was remanded to its originally filed court of the Western District of Wisconsin for trial.
In the other cases, on July 18, 2011, the Nevada district court granted our joint motions for summary judgment to preclude the plaintiffs’ state law claims because the federal Natural Gas Act gives the Federal Energy Regulatory Commission exclusive jurisdiction to resolve those issues. The court also denied the plaintiffs’ class certification motion as moot. The plaintiffs appealed to the United States Court of Appeals for the Ninth Circuit. On April 10, 2013, the United States Court of Appeals for the Ninth Circuit issued its opinion in the In re: Western States Wholesale Antitrust Litigation, holding that the Natural Gas Act does not preempt the plaintiffs’ state antitrust claims and reversing the summary judgment previously entered in favor of the defendants. The U.S. Supreme Court granted Defendants’ writ of certiorari. On April 21, 2015, the U.S. Supreme Court determined that the state antitrust claims are not preempted by the federal Natural Gas Act. On March 7, 2016, the putative class plaintiffs in several of the cases filed their motions for class certification. On March 30, 2017, the court denied the motions for class certification, which decision was appealed on June 20, 2017. On May 24, 2016, in Reorganized FLI Inc. v. Williams Companies, Inc., the Court granted Defendants’ Motion for Summary Judgment in its entirety, and an agreed amended judgment was entered by the court on January 4, 2017. Reorganized FLI, Inc. appealed this decision and on March 27, 2018, the 9th Circuit Court of Appeals reversed and remanded the case to the MDL Court. In May 2019, the MDL Court remanded the case back to Kansas District Court. On December 30, 2019, Defendants petitioned the United States Court of Appeals for the Tenth Circuit to consider their motion for appeal of their motion to reconsider the denial of their motion for summary judgement. Because of the uncertainty around pending unresolved issues, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential exposure at this time.
Other Indemnifications
Pursuant to various purchase and sale agreements relating to divested businesses and assets, including the agreements pursuant to which we divested our Piceance and San Juan Basin operations, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breaches of representations and warranties, tax liabilities, historic litigation, personal injury, environmental matters and rights-of-way. Additionally, Federal and state laws in areas of former operations may require previous operators to perform in certain circumstances where the buyer/operator may no longer be able to perform. Such duties may include plugging and abandoning wells or responsibility for surface agreements in existence at the time of disposition.
The current owner/operator of properties we divested in the Powder River Basin filed for bankruptcy during the fourth quarter of 2019, and it is uncertain to what extent the current owner/operator will perform its obligations with respect to such properties. Prior to our disposition of such properties, payments under the surface use agreements were approximately $6 million annually and our recorded asset retirement obligation under GAAP related to the plugging and abandoning of wells was approximately $46 million.
The indemnity provided to the purchaser of the entity that held our Piceance Basin operations relates in substantial part to liabilities arising in connection with litigation over the appropriate calculation of royalty payments. Plaintiffs in that litigation have asserted claims regarding, among other things, the method by which we accounted for transportation costs when calculating royalty payments. In 2017, we settled one of these claims.
As of December 31, 2019, we have not received any additional significant claims against any of these indemnities and thus have no basis from which to estimate any reasonably possible loss beyond any amount already accrued. Further, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. However, if a claim for indemnity is brought against us in the future, it may have a material adverse effect on our results of operations in the period in which the claim is made.
In connection with the separation from Williams, we agreed to indemnify and hold Williams harmless from any losses resulting from the operation of our business or arising out of liabilities assumed by us. Similarly, Williams has agreed to indemnify and hold us harmless from any losses resulting from the operation of its business or arising out of liabilities assumed by it.
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Notes to Consolidated Financial Statements-(Continued)
Summary
As of December 31, 2019 and December 31, 2018, the Company had accrued approximately $10 million and $11 million, respectively, for loss contingencies associated with royalty litigation and other contingencies. In certain circumstances, we may be eligible for insurance recoveries, or reimbursement from others. Any such recoveries or reimbursements will be recognized only when realizable.
Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, is not expected to have a materially adverse effect upon our future liquidity or financial position; however, it could be material to our results of operations in any given year.
Commitments
We have minimum commitments with midstream companies for gathering, treating, processing and transportation services associated with moving certain of our production to market. As part of managing our commodity price risk, we may also utilize contracted pipeline capacity to move our oil and natural gas production and third-party purchases of oil and natural gas to other locations in an attempt to obtain more favorable pricing differentials. The midstream service and transportation contract commitments disclosed below include obligations for which liabilities were recorded in 2015 associated with our exit from the Powder River Basin and our abandonment of an area in the Appalachian Basin. As of December 31, 2019, commitments and recorded liabilities associated with our midstream service and transportation contracts are as follows:
Our midstream service commitments will be settled over approximately seven years.
Total rent expense, excluding amounts capitalized, was $25 million and $19 million in 2018 and 2017, respectively. Rent charges incurred for drilling rig rentals are capitalized under the successful efforts method of accounting; however, charges for rig release penalties or long term standby charges are expensed as incurred.
Note 11. Leases
Our contracts that are leases or contain leases primarily relate to drilling rigs, compression units and office space. Leases are recorded on the balance sheet when the lease term exceeds one year and we direct the use of an identified asset while receiving substantially all of the economic benefit of the asset. Right-of-use assets are included in other noncurrent assets on the Consolidated Balance Sheet. Lease liabilities are included in accrued and other current liabilities and other noncurrent liabilities on the Consolidated Balance Sheet. We have elected to include both lease and non-lease components for all significant asset classes as a single lease component for measurement purposes. Leases with an initial term of 12 months or less are not recorded on the balance sheet and lease expense for these leases is recognized as incurred. We have elected to include lease costs associated with lease terms of one month or less in our short-term lease disclosure below.
We use judgments and assumptions to determine our discount rate and whether a contract contains a lease. The discount rate used to determine the lease payment liability is based on our estimated incremental borrowing rate.
Certain of our leases include rental payments adjusted periodically for inflation. Our lease agreements do not contain any material residual value guarantees or material restrictive covenants. From time to time we may enter into lease contracts that commence in future periods. Lease contracts that will commence subsequent to December 31, 2019 are not significant.
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Notes to Consolidated Financial Statements-(Continued)
The following tables include quantitative disclosures related to our leases.
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(a)Amounts are presented before recovery of amounts billed to or reimbursed by other working interest owners.
(b)Includes variable lease costs on short-term leases.
The following tables include quantitative disclosures related to our leases as of December 31, 2019.
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Notes to Consolidated Financial Statements-(Continued)
Note 12. Employee Benefit Plans
WPX has a defined contribution plan, which matches employee contributions dollar-for-dollar up to the first 6 percent of eligible pay per period. Employees also receive a non-matching annual employer contribution equal to 8 percent of eligible pay if they are age 40 or older and 6 percent of eligible pay if they are under age 40. Total contributions to this plan were $10 million, $10 million and $11 million for 2019, 2018 and 2017, respectively. Approximately $7 million was included in accrued and other current liabilities at both December 31, 2019, and 2018 related to the non-matching annual employer contribution.
Note 13. Stock-Based Compensation
We have an equity incentive plan (“2013 Incentive Plan”) and an employee stock purchase plan (“ESPP”). The 2013 Incentive Plan authorizes the grant of nonqualified stock options, incentive stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units and other stock-based awards (restricted stock awards, restricted stock units, performance shares and performance units are collectively referred to as restricted stock units and awards for purposes of this footnote). During 2018, the 2013 Incentive Plan was amended to authorize an additional 7.4 million shares for issuance under the plan. At December 31, 2019, 15 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 8 million shares were available for future grants. The 2013 Incentive Plan is administered by either the full Board of Directors or a committee as designated by the Board of Directors, determined by the grant. Our employees, officers and non-employee directors are eligible to receive awards under the 2013 Incentive Plan.
Total stock-based compensation expense was $34 million, $32 million and $28 million for of the years ended December 31, 2019, 2018 and 2017, respectively, and is reflected in general and administrative expense. Measured but unrecognized stock-based compensation expense related to restricted stock units and awards at December 31, 2019 was $44 million and is expected to be recognized over a weighted-average period of 2.6 years. There was no unrecognized stock-based compensation expense related to stock options at December 31, 2019.
The ESPP allows employees the option to purchase WPX common stock at a 15 percent discount through after-tax payroll deductions. The purchase price of the stock is the lower of either the first or last day of the biannual offering periods, followed with the 15 percent discount. The maximum number of shares that shall be made available under the purchase plan is 1 million shares, subject to adjustment for stock splits and similar events. During 2018, the ESPP was amended to replenish the number of shares of our common stock that may be issued under the ESPP by 750 thousand. Offering periods are from January through June and from July through December. Employees purchased 106 thousand shares at an average price of $9.82 per share during 2019.
Nonvested Restricted Stock Units and Awards
The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2019.
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(a) Performance-based shares are valued utilizing a Monte Carlo valuation method using measures of total shareholder return. All other shares are valued at the grant-date market price.
Other restricted stock unit information
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Notes to Consolidated Financial Statements-(Continued)
Performance-based shares granted represent 35 percent of nonvested restricted stock units outstanding at December 31, 2019. These grants may be earned at the end of a three year period based on actual performance against a performance target. Expense associated with these performance-based grants is recognized in periods after performance targets are established. Based on the extent to which certain financial targets are achieved, vested shares may range from zero to 200 percent of the original grant amount.
Stock Options
The following summary reflects stock option activity and related information for the year ended December 31, 2019.
The total intrinsic value of options exercised was $468 thousand, $4.3 million and $224 thousand for the years ended December 31, 2019, 2018 and 2017, respectively.
Cash received from stock option exercises was $0.5 million, $9.2 million and $0.4 million during 2019, 2018 and 2017, respectively.
The Company did not grant stock options during the years ended 2019, 2018 and 2017.
Note 14. Stockholders’ Equity
Preferred Stock
Our amended and restated certificate of incorporation authorizes our Board of Directors to establish one or more series of preferred stock. Unless required by law or by any stock exchange on which our common stock is listed, the authorized shares of preferred stock will be available for issuance without further action. Rights and privileges associated with shares of preferred stock are subject to authorization by our Board of Directors and may differ from those of any and all other series at any time outstanding. As of December 31, 2019, we have no preferred shares outstanding.
Common Stock
Each share of our common stock entitles its holder to one vote in the election of each director. No share of our common stock affords any cumulative voting rights. Holders of our common stock will be entitled to dividends in such amounts and at such times as our Board of Directors in its discretion may declare out of funds legally available for the payment of dividends. No dividends on our common stock were declared or paid for 2019, 2018 or 2017. No shares of common stock are subject to redemption or have preemptive rights to purchase additional shares of our common stock or other securities.
Subject to certain exceptions, so long as any share of our Preferred Stock remains outstanding, no dividend or distribution shall be declared or paid on the shares of the Company’s common stock or any other class or series of junior stock, and no common stock or any other class or series of junior or parity stock shall be purchased, redeemed or otherwise acquired for consideration by the Company or any of its subsidiaries unless all accumulated and unpaid dividends for all preceding dividend periods have been declared and paid upon, or a sufficient sum of cash or number of shares of the Company’s common stock has been set apart for the payment of such dividends upon, all outstanding shares of Preferred Stock.
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Notes to Consolidated Financial Statements-(Continued)
On January 12, 2017, we completed an underwritten public offering of 51.675 million shares of our common stock, which included 6.675 million shares of common stock issued pursuant to an option granted to the underwriters to purchase additional shares. The stock was sold to the underwriters at $12.97 per share and we received proceeds of approximately $670 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions. We used these proceeds, and cash on hand, to close an acreage acquisition in the Delaware Basin.
Stock Repurchase Program
On August 5, 2019, we announced that our Board of Directors authorized a plan to repurchase up to $400 million of our outstanding shares over a 24 month period. Under the share repurchase program, we may repurchase shares at management’s discretion in accordance with applicable securities laws, including through open market transactions, privately negotiated transactions or any combination thereof. The amount and timing of repurchases are subject to a number of factors, including stock price, trading volume, general market conditions, legal requirements, general business conditions and corporate considerations determined by WPX’s management, such as liquidity and capital needs. This share repurchase program may be modified, suspended or terminated at any time by our Board of Directors. As of December 31, 2019, we have repurchased approximately 5.7 million shares under the program at an average price of $10.16.
Transaction Costs Related to Partnerships
In September and October 2019, we entered into strategic relationships with two third-parties through two newly-formed subsidiaries for purposes of acquiring mineral interests and funding participation in future non-operated well interests. In accordance with and subject to the terms of the agreements, both parties have committed to fund future contributions, subject to certain limits, through the end of 2020 and 2022, respectively. The third-party contributions would represent 80 percent to 85 percent of the total contributions to the partnerships. During 2019, we incurred approximately $6 million of partnership equity commitment and issuance costs, which are recognized as a reduction of additional paid-in-capital within stockholders’ equity attributable to WPX. The Company will be entitled to receive varying percentages of returns based upon achievement of certain predetermined thresholds.
WPX holds a controlling financial interest in these partnerships. Accordingly, we will consolidate the financial results of these entities and will present the portion attributable to the third parties as a noncontrolling interest in our consolidated financial statements.
Note 15. Fair Value Measurements
Fair value is the amount received from the sale of an asset or the amount paid to transfer a liability in an orderly transaction between market participants (an exit price) at the measurement date. Fair value is a market-based measurement considered from the perspective of a market participant. We use market data or assumptions that we believe market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation. These inputs can be readily observable, market corroborated or unobservable. We apply both market and income approaches for recurring fair value measurements using the best available information while utilizing valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.
The fair value hierarchy prioritizes the inputs used to measure fair value, giving the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). We classify fair value balances based on the observability of those inputs. The three levels of the fair value hierarchy are as follows:
•Level 1-Quoted prices for identical assets or liabilities in active markets that we have the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 measurements primarily consist of financial instruments that are exchange traded.
•Level 2-Inputs are other than quoted prices in active markets included in Level 1 that are either directly or indirectly observable. These inputs are either directly observable in the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured. Our Level 2 measurements primarily consist of over-the-counter (“OTC”) instruments such as forwards, swaps and options. These options, which hedge future sales of production, are structured as costless collars, calls or swaptions and are financially settled. They are valued using an industry standard Black-Scholes option pricing model. Also categorized as Level 2 is the fair value of our debt, which is determined on market rates and the prices of similar securities with similar terms and credit ratings.
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Notes to Consolidated Financial Statements-(Continued)
•Level 3-Inputs that are not observable for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value. Our Level 3 measurements consist of instruments valued using industry standard pricing models and other valuation methods that utilize unobservable pricing inputs that are significant to the overall fair value.
In valuing certain contracts, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. For disclosure purposes, assets and liabilities are classified in their entirety in the fair value hierarchy level based on the lowest level of input that is significant to the overall fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels.
The following table presents, by level within the fair value hierarchy, our assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents and restricted cash approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.
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(a) The carrying value of total debt, excluding debt issuance costs, was $2,229 million and $2,509 million as of December 31, 2019 and 2018, respectively.
Energy derivatives include commodity-based exchange-traded contracts and over-the-counter (“OTC”) contracts. Exchange-traded contracts include futures, swaps and options. OTC contracts include forwards, swaps, options or swaptions. These are carried at fair value on the Consolidated Balance Sheets.
Many contracts have bid and ask prices that can be observed in the market. Our policy is to use a mid-market pricing (the mid-point price between bid and ask prices) convention to value individual positions and then adjust on a portfolio level to a point within the bid and ask range that represents our best estimate of fair value. For offsetting positions by location, the mid-market price is used to measure both the long and short positions.
The determination of fair value for our derivative assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our liabilities. The determination of the fair value of our liabilities does not consider noncash collateral credit enhancements.
Forward, swap, option and swaption contracts are considered Level 2 and are valued using an income approach including present value techniques and option pricing models. Option contracts, which hedge future sales of our production, are structured as calls, costless collars, or swaptions and are financially settled. All of our financial options are valued using an industry standard Black-Scholes option pricing model. In connection with swaps, we may sell call options or swaptions to the swap counterparties in exchange for receiving premium hedged prices on the swaps. The sold calls or swaptions establish a maximum price we will receive for the volumes under contract and are financially settled. Significant inputs into our Level 2 valuations include commodity prices, implied volatility and interest rates, as well as considering executed transactions or broker quotes corroborated by other market data. These broker quotes are based on observable market prices at which transactions could currently be executed. In certain instances where these inputs are not observable for all periods, relationships of observable market data and historical observations are used as a means to estimate fair value. Also categorized as Level 2 is the fair value of our debt, which is determined on market rates and the prices of similar securities with similar terms and credit ratings. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.
Our energy derivatives portfolio is largely comprised of over-the-counter products or like products and the tenure of our derivatives portfolio extends through the end of 2023. Due to the nature of the products and tenure, we are consistently able to obtain market pricing. All pricing is reviewed on a daily basis and is formally validated with broker quotes or market indications and documented on a monthly basis.
Certain instruments trade with lower availability of pricing information. These instruments are valued with a present value technique using inputs that may not be readily observable or corroborated by other market data. These instruments are classified
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Notes to Consolidated Financial Statements-(Continued)
within Level 3 when these inputs have a significant impact on the measurement of fair value. We had instruments totaling less than $1 million and $3 million included in Level 3 as of December 31, 2019 and 2018, respectively.
Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No significant transfers between Level 1, Level 2 and Level 3 occurred during the years ended December 31, 2019 or 2018.
Realized and unrealized gains (losses) included in income (loss) from continuing operations for the above periods are reported in revenues on our Consolidated Statements of Operations.
Other
In addition to the items discussed below, we performed other nonrecurring fair value assessments as discussed in Note 2.
In conjunction with the $103 million of gains from exchanges of leasehold during 2017, we estimated the fair value of the leasehold through discounted cash flow models and consideration of market data. Our estimates and assumptions include future commodity prices, projection of estimated quantities of oil and natural gas reserves, expectations for future development and operating costs and risk adjusted discount rates, all of which are Level 3 inputs. The total fair value of leasehold exchanges in 2017 approximated $200 million. See Note 4 for additional discussion related to leasehold exchanges.
In addition, during the third quarter of 2017, we began a process to market our natural gas-producing properties in the San Juan Basin and our Board of Directors approved a divestment subject to a minimum price. Following the marketing process, we received several acceptable bids. As a result, we determined the estimated fair value, less costs to sell, based on the probability-weighted cash flows of expected proceeds and compared it to our net book value which resulted in an impairment of $60 million recorded in the third quarter of 2017. See Note 2 for additional discussion related to the impairment of our natural gas-producing properties in the San Juan Basin reported as discontinued operations.
Note 16. Derivatives and Concentration of Credit Risk
Energy Commodity Derivatives
Risk Management Activities
We are exposed to market risk from changes in energy commodity prices within our operations. We utilize derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of crude oil, natural gas and natural gas liquids attributable to commodity price risk.
We produce, buy and sell crude oil, natural gas and natural gas liquids at different locations throughout the United States. To reduce exposure to a decrease in revenues from fluctuations in commodity market prices, we enter into futures contracts, swap agreements, and financial option contracts to mitigate the price risk on forecasted sales of crude oil, natural gas and natural gas liquids. We have also entered into basis swap agreements to reduce the locational price risk associated with our producing basins. Our financial option contracts are either purchased or sold options, or a combination of options that comprise a net purchased option, zero-cost collar or swaptions.
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Notes to Consolidated Financial Statements-(Continued)
Derivatives related to production
The following table sets forth the derivative notional volumes of the net long (short) positions that are economic hedges of production volumes, which are included in our commodity derivatives portfolio as of December 31, 2019.
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(a) Derivatives related to crude oil production are fixed price swaps settled on the business day average, basis swaps, fixed price calls, collars or swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, fixed price calls and swaptions. In connection with swaps, we may sell call options or swaptions to the swap counterparties in exchange for receiving premium hedge prices on the swaps. The sold call or swaption establishes a maximum price we will receive for the volumes under contract and are financially settled. Basis swaps for the Nymex CMA (Calendar Monthly Average) Roll location are pricing adjustments to the trade month versus the delivery month for contract pricing. Basis swaps for the Brent/WTI location are priced off the Brent and WTI futures spread.
(b) Crude oil volumes are reported in Bbl/day and natural gas volumes are reported in BBtu/day.
(c) The weighted average price for crude oil is reported in $/Bbl and the natural gas is reported in $/MMBtu.
(d) Fixed Price Swaps include hedges related to a new partnership created to fund non-operated interests.
Fair values and gains (losses)
Our derivatives are presented as separate line items in our Consolidated Balance Sheets as current and noncurrent derivative assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual timing of expected future net cash flows of individual contracts. The expected future net cash flows for derivatives classified as current are expected to occur within the next 12 months. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, our derivatives do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions.
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Notes to Consolidated Financial Statements-(Continued)
We enter into commodity derivative contracts that serve as economic hedges but are not designated as cash flow hedges for accounting purposes as we do not utilize this method of accounting for derivative instruments. The following table presents the net gain (loss) related to our energy commodity derivatives.
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(a) Includes settlements totaling $12 million for the year ended December 31, 2019, payments totaling $237 million for the year ended December 31, 2018, and settlements totaling $4 million for the year ended December 31, 2017.
(b) Includes payments totaling less than $1 million for the years ended December 31, 2019, 2018 and 2017.
The cash flow impact of our derivative activities is presented as separate line items within the operating activities on the Consolidated Statements of Cash Flows.
Offsetting of derivative assets and liabilities
The following table presents our gross and net derivative assets and liabilities.
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(a) With all of our financial trading counterparties, we have agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. Additionally, we have negotiated master netting agreements with some of our counterparties. These master netting agreements allow multiple entities that have multiple underlying agreements the ability to net derivative assets and derivative liabilities at settlement or in the event of a default or a termination under one or more of the underlying contracts.
Credit-risk-related features
Certain of our derivative contracts contain credit-risk-related provisions that would require us, under certain events, to post additional collateral in support of our net derivative liability positions. These credit-risk-related provisions require us to post collateral in the form of cash or letters of credit when our net liability positions exceed an established credit threshold. The credit thresholds are typically based on our senior unsecured debt ratings from Standard and Poor’s and/or Moody’s Investment Services. Under these contracts, a credit ratings decline would lower our credit thresholds, thus requiring us to post additional collateral. We also have contracts that contain adequate assurance provisions giving the counterparty the right to request collateral in an amount that corresponds to the outstanding net liability.
As of December 31, 2019, we did not have any collateral posted to derivative counterparties to support the aggregate fair value of our net $46 million derivative liability position (reflecting master netting arrangements in place with certain counterparties) which includes a reduction of less than $1 million to our liability balance for our own nonperformance risk. As of December 31, 2018, we did not have any collateral posted to derivative counterparties to support the aggregate fair value of our net less than $1 million derivative liability position (reflecting master netting arrangements in place with certain counterparties) which includes a reduction of $1 million to our liability balance for our own nonperformance risk. The additional collateral that we would have been required to post, assuming our credit thresholds were eliminated and a call for adequate assurance under the credit risk provisions in our derivative contracts was triggered, was $46 million and less than $1 million at December 31, 2019 and 2018, respectively.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Concentration of Credit Risk
Cash equivalents
Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.
Accounts receivable
The following table summarizes concentration of receivables, net of allowances, by product or service as of dates indicated below.
Oil and natural gas customers include pipelines, distribution companies, producers, marketers and industrial users primarily located in the southwestern United States and North Dakota. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly.
Derivative assets and liabilities
We have a risk of loss from counterparties not performing pursuant to the terms of their contractual obligations. Counterparty performance can be influenced by changes in the economy and regulatory issues, among other factors. Risk of loss is impacted by several factors, including credit considerations and the regulatory environment in which a counterparty transacts. We attempt to minimize credit-risk exposure to derivative counterparties and brokers through formal credit policies, consideration of credit ratings from public ratings agencies, monitoring procedures, master netting agreements and collateral support under certain circumstances. Collateral support could include letters of credit, payment under margin agreements and guarantees of payment by creditworthy parties.
We also enter into master netting agreements to mitigate counterparty performance and credit risk. During 2019, 2018 and 2017, we did not incur any significant losses due to counterparty bankruptcy filings. We assess our credit exposure on a net basis to reflect master netting agreements in place with certain counterparties. We offset our credit exposure to each counterparty with amounts we owe the counterparty under derivative contracts.
Our gross and net credit exposure from our derivative contracts were $67 million and $22 million, respectively, as of December 31, 2019. All of our credit exposure is with investment grade financial institutions. We determine investment grade primarily using publicly available credit ratings. We consider counterparties with a minimum S&P’s rating of BBB- or Moody’s Investors Service rating of Baa3 to be investment grade.
Our five largest net counterparty positions represent approximately 98 percent of our net credit exposure. Under our marginless hedging agreements with key banks, neither party is required to provide collateral support related to hedging activities.
Other
At December 31, 2019, we held collateral support of $40 million, either in the form of cash, letters of credit or surety bond, related to our commodity management agreements.
Collateral support for our commodity agreements could include margin deposits, letters of credit, and guarantees of payment by credit worthy parties.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Revenues
The following companies accounted for more than 10 percent of our total consolidated revenues adjusted for net gain (loss) on derivatives in any given year presented below. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on the financial position or results of operations of the Company.
__________
(a) Revenues for purchaser were less than 10 percent of total consolidated revenues adjusted for net gain (loss) on derivatives.
One of our senior officers is on the board of directors of NGL Energy Partners, LP ("NGL Energy"). In the normal course
of business, we sell crude oil to a subsidiary of NGL Energy, noted in the table above as NGL Crude Logistics. In addition, a subsidiary of NGL Energy provides water disposal services for WPX that represent less than 2 percent of operating expenses.
Note 17. Pending Felix Acquisition
On December 15, 2019, we entered into a Securities Purchase Agreement (the "Purchase Agreement") with Felix Investments Holdings II, LLC ("Felix Parent") to acquire all of the issued and outstanding membership interests of Felix Energy ("Felix") (collectively, the "Felix Acquisition"), for consideration of approximately $2.5 billion (the "Unadjusted Purchase Price"), consisting of $900 million in cash (the "Unadjusted Cash Purchase Price"), and 152,963,671 unregistered shares of our common stock (the "Unadjusted Equity Consideration") determined by dividing $1.6 billion by $10.46, the volume weighted average per share price of the Company for the ten consecutive trading days ending on December 13, 2019. The Unadjusted Purchase Price is subject to certain customary closing adjustments set forth in the Purchase Agreement. If certain closing adjustments are positive, the Unadjusted Cash Purchase Price is adjusted and if certain closing adjustments are negative, the Unadjusted Equity Consideration is adjusted. WPX plans to fund the cash portion through the issuance of $900 million of senior notes (see "Financing Transaction" below). We expect to close the Felix Acquisition in the first quarter of 2020, subject to satisfaction of customary closing conditions and pending shareholder approval. As of December 31, 2019, we have accrued approximately $3 million of acquisition bridge facility fees, included in interest expense, and approximately $3 million of acquisition costs, primarily related to legal and advisory fees, reflected on a separate line item on the Consolidated Statement of Operations. Additional expenses will be incurred upon closing.
Felix Parent has a senior secured notes facility pursuant to that certain Note Purchase Agreement, dated as of August 9, 2017 (as amended, restated, amended and restated, supplemented and otherwise modified prior to the date hereof, the "Felix Parent Notes Facility"), and Felix has a reserve-based revolving credit facility pursuant to that certain Credit Agreement dated as of July 1, 2016 (as amended, restated, amended and restated, supplemented and otherwise modified prior the date hereof, the "Felix Revolving Credit Facility" and together with the Felix Parent Notes Facility, the "Felix Debt Facilities"). The Felix Parent Notes Facility is secured by a lien on the equity of Felix and certain of Felix's assets. As a condition to and simultaneous with the closing of the Felix Acquisition, all remaining amounts outstanding under the Felix Debt Facilities are to be repaid in order to cause the release of such liens and terminate the facilities. Any amounts outstanding under the Felix Debt Facilities that are repaid from the Unadjusted Cash Purchase Price in connection with and simultaneous with the closing of the Felix Acquisition will result in a reduction in the Unadjusted Cash Purchase Price received by Felix Parent. Furthermore, in connection with entering into the Purchase Agreement, Felix Parent received commitments from certain of its affiliates to finance the repayment of any amounts outstanding under the Felix Debt Facilities to the extent such amounts outstanding exceed the Unadjusted Cash Purchase Price subject to certain adjustments.
Pursuant to the Purchase Agreement, Felix Parent will receive our common stock as consideration and Felix Parent (and/or certain of Felix Parent's direct or indirect equity holders) will have registration rights with respect to such common stock. Following the acquisition, Felix will be our wholly-owned subsidiary.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Felix is engaged in the acquisition, development and production of oil and gas properties in the Permian Basin, and more specifically in the Delaware Basin sub-area. All of Felix's Permian properties are located in the Delaware Basin and include approximately 58,500 net acres with six productive benches, with core operations located in Loving, Reeves, Ward and Winkler counties in Texas. Felix has assembled a multi-year inventory of approximately 1,500 gross drillable locations.
Financing Transaction
On January 10, 2020, we completed our debt offering of $900 million aggregate principal amount of 4.50% senior unsecured notes due 2030 (the "2030 Notes"). The proceeds were deposited into an escrow account upon the closing of the offering. Upon release from escrow, WPX intends to use the proceeds to finance a portion of the cash consideration of the Felix Acquisition and to pay certain fees and expenses.
The Notes are the Company’s senior unsecured obligations ranking equally with the Company’s other existing and future senior unsecured indebtedness. The 2030 Notes bear interest at a rate of 4.50% per annum and were priced at 100.0% of par. Interest is payable on the 2030 Notes semi-annually in arrears on January 15 and July 15 of each year commencing on July 15, 2020. The 2030 Notes will mature on January 15, 2030. At any time prior to January 15, 2023, the Company may, on one or more occasions and subject to certain conditions described in the Indenture, redeem up to 35% of the aggregate principal amount of the Notes at a redemption price equal to 104.5% of the principal amount of the Notes redeemed with an amount of cash not greater than the net proceeds that the Company raises in certain equity offerings, as described in the Indenture. The Company also has the option, at any time prior to January 15, 2025, on one or more occasions, to redeem some or all of the Notes at a redemption price equal to 100% of the principal amount of the Notes to be redeemed, plus a specified “make whole” premium as described in the Indenture. At any time on or after January 15, 2025, the Company may, on one or more occasions, redeem the Notes, in whole or in part, at the applicable redemption prices set forth in the Indenture. The Indenture contains covenants that, among other things, restrict the Company’s ability to grant liens on its assets and merge, consolidate or transfer or lease all or substantially all of its assets, subject to certain qualifications and exceptions.
WPX Energy, Inc.
QUARTERLY FINANCIAL DATA
(Unaudited)
Summarized quarterly financial data is presented below. The sum of earnings per share for the four quarters may not equal the total earnings per share for the year due to rounding.
Net income or loss for each respective quarter include the following pre-tax items:
First-quarter 2019:
•$126 million gain on sale of our 20 percent equity interest in the Whitewater natural gas pipeline (see Note 5).
Second-quarter 2019:
•$247 million gain related to a distribution received for our 25 percent equity interest in the Oryx pipeline partnership after the underlying assets were sold (see Note 5).
Third-quarter 2019:
•$47 million loss on extinguishment of debt (see Note 8).
•$11 million charge included in Other-net on the Consolidated Statements of Operations associated with an offer made by us to settle certain contractual disputes in the Williston Basin (see Note 4).
Fourth-quarter 2019:
•$7 million additional gain on sale of our 20 percent equity interest in the Whitewater natural gas pipeline (see Note 5).
First-quarter 2018:
•$138 million loss included in discontinued operations for the sale of the San Juan Gallup and $9 million performance guarantee related to gathering and processing commitments (see Note 2).
Second-quarter 2018:
•$71 million loss on extinguishment of debt (see Note 8).
WPX Energy, Inc.
Supplemental Oil and Gas Disclosures
(Unaudited)
We have significant continuing oil and gas producing activities primarily in the Delaware Basin in Texas and New Mexico and the Williston Basin in North Dakota, all of which are located in the United States.
The following information includes activity through the completion of any asset sales. These sales include operations which are reported within continuing operations and the operations of the San Juan Basin, which have been reported as discontinued operations in our consolidated financial statements. The San Juan Basin properties were sold in March 2018 and December 2017.
Capitalized Costs
__________
•Excluded from capitalized costs are equipment and facilities in support of oil and gas production of $350 million and $276 million, net, as of December 31, 2019 and 2018, respectively.
•Proved properties include capitalized costs for oil and gas leaseholds holding proved reserves, development wells including uncompleted development well costs and successful exploratory wells.
•Unproved properties consist primarily of unproved leasehold costs.
Cost Incurred
__________
•Costs incurred include capitalized and expensed items but excludes costs associated with facilities.
•Acquisition costs are as follows: Costs in 2019 primarily reflect the purchase of surface acreage within our Delaware Basin acreage. Costs in 2018 primarily relate to purchase of acreage in the Delaware Basin and include $13 million and 0.6 MMboe of proved reserves. Costs in 2017 primarily relate to our purchase of assets in the Delaware Basin in March 2017 that included approximately $200 million and 23.8 MMboe of proved developed reserves and facilities.
•Exploration costs include costs incurred for geological and geophysical activity, drilling and equipping exploratory wells, including costs incurred during the year for wells determined to be dry holes, exploratory lease acquisitions and retaining undeveloped leaseholds.
•Development costs include costs incurred to gain access to and prepare well locations for drilling and to drill and equip wells in our development basins. Development costs associated with our San Juan Basin operations were $24 million and $168 million for 2018 and 2017, respectively.
WPX Energy, Inc.
Supplemental Oil and Gas Disclosures
(Unaudited)
Proved Reserves
The SEC defines proved oil and gas reserves (Rule 4-10(a) of Regulation S-X) as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved reserves consist of two categories, proved developed reserves and proved undeveloped reserves. Proved developed reserves are currently producing wells and wells awaiting minor sales connection expenditure, recompletion, additional perforations or borehole stimulation treatments. Proved undeveloped reserves are those reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved reserves on undrilled acreage are limited to those that can be developed within five years according to planned drilling activity. Proved reserves on undrilled acreage also can include locations that are more than one offset away from current producing wells where there is a reasonable certainty of production when drilled or where it can be demonstrated with reasonable certainty that there is continuity of production from the existing productive formation.
WPX Energy, Inc.
Supplemental Oil and Gas Disclosures
(Unaudited)
The following is a summary of changes in our proved reserves including proved reserves activity through the completion of our sales of the San Juan and Piceance Basins which are reported as discontinued operations and other divestitures in continuing operations.
__________
•Natural gas reserves are computed at 14.73 pounds per square inch absolute and 60 degrees Fahrenheit.
•Revisions in 2019 primarily reflect 21 MMboe of positive technical revisions partially offset by 16 MMboe of negative revisions due to a decrease in the 12 month average price. Revisions in 2018 primarily reflect 9 MMboe of positive revisions due to an increase in the 12 month average price offset by 5 MMboe of negative revisions. Revisions in 2017 primarily reflect 24 MMboe of positive revision due to an increase in the 12 month average price offset by 22 MMboe negative revisions primarily due to changes in the development plan for certain natural gas wells.
•Purchases in 2017 primarily reflect the Panther Acquisition of which 23.8 MMboe is proved developed.
•Divestitures in 2018 primarily relate to the sale of our oil assets in the San Juan Basin which included 40 MMboe of proved developed reserves and 11 MMboe of proved undeveloped reserves. Divestitures in 2017 primarily relate to the sale of our natural gas assets in the San Juan Basin which included 28.7 MMboe of proved developed reserves and 16.6 MMboe of proved undeveloped reserves.
•Extensions and discoveries in 2019 reflect 42 MMboe added for proved developed locations primarily in the Permian Basin and 68 MMboe added for proved undeveloped locations in the Permian Basin. Extensions and discoveries in 2018 reflect 52 MMboe added for proved developed locations and 85 MMboe of proved undeveloped locations. Extensions and discoveries in 2017 reflect 46 MMboe added for proved developed locations and 97 MMboe of proved undeveloped locations primarily in the Delaware and Williston Basins.
WPX Energy, Inc.
Supplemental Oil and Gas Disclosures
(Unaudited)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following is based on the estimated quantities of proved reserves. Prices were calculated from the 12-month trailing average, first-of-the-month price for the applicable indices for each basin as adjusted for respective location price differentials. The average domestic oil price used in the estimates for the years ended December 31, 2019, 2018 and 2017 was $53.62, $61.57 and $46.39 per barrel, respectively. The average natural gas price used in the estimates for the years ended December 31, 2019, 2018 and 2017 was $0.97, $1.21 and $1.67 per Mcf, respectively. The average NGL price per barrel was $13.23, $26.76 and $21.16 for the same periods. Future income tax expenses have been computed considering applicable taxable cash flows, including historical tax basis and carry forwards (i.e. future deductions for taxable income calculations), and appropriate statutory tax rates. The discount rate of 10 is as prescribed by authoritative guidance. Continuation of year-end economic conditions also is assumed. The calculation is based on estimates of proved reserves, which are revised over time as new data becomes available. Probable or possible reserves, which may become proved in the future, are not considered. The calculation also requires assumptions as to the timing of future production of proved reserves, and the timing and amount of future development and production costs.
Numerous uncertainties are inherent in estimating volumes and the value of proved reserves and in projecting future production rates and timing of development expenditures. Such reserve estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production may be substantially different from the reserve estimates.
Standardized Measure of Discounted Future Net Cash Flows
Sources of Change in Standardized Measure of Discounted Future Net Cash Flows
WPX Energy, Inc.
SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS
__________
(a) Deducted from related assets.
(b) Deducted from related liabilities.
(c) Included in revenues.
(d) Includes impact of the Tax Cuts and Jobs Act enacted rate reduction.
Item 9.
Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A.Controls and Procedures
Disclosure Controls and Procedures
Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act) (“Disclosure Controls”) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant.
Evaluation of Disclosure Controls and Procedures
An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief
Executive Officer and Chief Financial Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.
Management’s Annual Report on Internal Control over Financial Reporting
See report set forth in Item 8, “Financial Statements and Supplementary Data.”
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting
See report set forth in Item 8, “Financial Statements and Supplementary Data.”
Fourth Quarter 2019 Changes in Internal Controls
There have been no changes during the fourth quarter of 2019 that have materially affected, or are reasonably likely to materially affect our internal controls over financial reporting.
Item 9B.
Item 9B.Other Information
None.
PART III
Item 10.
Item 10.Directors, Executive Officers and Corporate Governance
The information called for by this Item 10 is incorporated by reference to our definitive proxy statement for our 2020 Annual meeting of Stockholders, or our 2020 Proxy Statement, anticipated to be filed with the Securities and Exchange Commission within 120 days of December 31, 2019, under the headings “Proposal 1- Election of Directors,” “Corporate Governance,” and “Section 16(a) Beneficial Ownership and Reporting Compliance.”
The information called for by this Item 11
Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information called for by this Item 12 is incorporated by reference to our 2020 Proxy Statement anticipated to be filed with the Securities and Exchange Commission within 120 days of December 31, 2019, under the headings “Security Ownership of Certain Beneficial Owners and Management” and “Equity Compensation Plan Information.”
Item 13.
Item 13.Certain Relationships and Related Transactions, and Director Independence
The information called for by this Item 13 is incorporated by reference to our 2020 Proxy Statement anticipated to be filed with the Securities and Exchange Commission within 120 days of December 31, 2019, under the headings “Corporate Governance” and “Certain Relationships and Transactions.”
Item 14.
Item 14.Principal Accountant Fees and Services
The information called for by this Item 14 is incorporated by reference to our 2020 Proxy Statement anticipated to be filed with the Securities and Exchange Commission within 120 days of December 31, 2019, under the heading “Independent Registered Public Accounting Firm.”
PART IV
Item 15.
Item 15.Exhibits and Financial Statement Schedules
(a) 1 and 2.
(a) 3 and (b). The exhibits listed below are filed as part of this annual report.
INDEX TO EXHIBITS
*Filed herewith
**All schedules to the Merger Agreement have been omitted pursuant to Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule and/or exhibit will be furnished to the SEC upon request.
(1)Management contract or compensatory plan or arrangement
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.
WPX ENERGY, Inc.
(Registrant)
By:/s/ Stephen L. Faulkner
Stephen L. Faulkner
Controller
(Principal Accounting Officer)
Date: February 27, 2020
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.