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 11 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 20, 2019, there were 6,517 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.
Item 6.
Item 6.Selected Financial Data
The following financial data at December 31, 2018 and 2017, and for each of the three years ended December 31, 2018, 2017 and 2016 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.
__________
(a) Income (loss) from continuing operations includes significant pre-tax items comprised of the following:
See Note 5 of Notes to Consolidated Financial Statements for further discussion of the impairments and asset sales in 2018, 2017 and 2016. 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, holdings in the Powder River Basin, and Apco Oil and Gas International Inc. Significant components included in income (loss) from discontinued operations are comprised of the following:
See Note 3 of Notes to Consolidated Financial Statements for further discussion of discontinued operations in 2018, 2017 and 2016.
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 working interest owners in operated wells and other third-party producers and, to a lesser extent, the management of various natural gas related contracts such as transportation and storage. 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 March 2017, we completed the acquisition of certain assets in the Delaware Basin (the “Panther Acquisition”). See Note 2 of Notes to Consolidated Financial Statements for a further discussion of this acquisition.
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. We also had operations in the Piceance Basin in Colorado until April 8, 2016. For all periods presented, the results of the San Juan and Piceance Basins are reported as discontinued operations. See Note 3 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. 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
Our 2018 oil production as a percent of total production declined compared to 2017 due to Delaware production growth which has a higher natural gas component than our Williston production. The following table presents our production volumes and financial highlights for 2018, 2017 and 2016:
__________
Our 2018 operating results were $456 million favorable compared to 2017. The primary items impacting 2018 results compared to 2017 results include:
•$1,009 million increase in product revenues, primarily oil sales, of which $501 million related to higher oil volumes and $410 million related to higher oil prices; and
•$78 million favorable change in net gain on derivatives.
Offset by:
•$500 million higher operating costs including depreciation, depletion and amortization, lease and facility, gathering, processing and transportation, and taxes other than income; and
•The absence in 2018 of $161 million net gain on sales of assets, including leasehold exchanges, which were included in 2017 (see Note 5 of Notes to Consolidated Financial Statements).
Our 2017 operating results were $924 million favorable compared to 2016. The primary items impacting 2017 results compared to 2016 results include:
•$509 million increase in product revenues, primarily oil sales, of which $239 million related to higher oil volumes and $189 million related to higher oil prices;
•$210 million favorable change in net gain (loss) on derivatives;
•$161 million net gain on sales of assets, including leasehold exchanges, for 2017 compared to $239 million net loss primarily related to divestment of transportation contracts for 2016 (see Note 5 of Notes to Consolidated Financial Statements); and
•$36 million decrease in general and administrative expenses.
Offset by:
•$199 million higher operating costs including depreciation, depletion and amortization, lease and facility, gathering, processing and transportation, and taxes other than income; and
•$61 million higher exploration costs (see Note 5 of Notes to Consolidated Financial Statements).
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 top geology in the plays and in North America. We have 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 have made additional investments during 2018 in our equity positions in Whitewater and Oryx pipeline systems. We believe we are well positioned for prudent and disciplined growth assuming a constructive commodity price environment. For 2019, we currently expect our operating cash flows to approximate our base capital expenditures plan. However, the challenging and dynamic environment of oil and gas industry, along with future market conditions, may alter these expectations or plans. We would make appropriate adjustments to our plans if we foresee other-than-temporary changes in market conditions, including significant fluctuation in expected commodity prices.
Our expected base capital budget for full year 2019 is $1.1 billion to $1.275 billion excluding land purchases. This is a reduction from our estimates previously communicated as we respond to the decline in oil prices toward the end of 2018. Additionally, we estimate between $70 million and $90 million for equity method investments. Planned capital for drilling and completions, including non-operated wells, is $1.050 billion to $1.175 billion for the full year 2019. Additionally and subsequent to December 31, 2018, we have signed or closed separate sales agreements for aggregate proceeds in excess of $200 million for our 20 percent equity interest in Whitewater and roughly 5,600 net acres in the Delaware Basin, while closing on a purchase of 14,000 surface acres for $100 million. WPX may also monetize its equity position in the Oryx pipeline systems.
Our December 31, 2018 liquidity totaled approximately $1.1 billion, reflecting amounts available under the Credit Facility Agreement and cash on hand. Our next Senior Note maturity of $529 million is not due until 2022. Our Credit Facility Agreement is subject to a $2.0 billion borrowing base with aggregate elected commitments of $1.5 billion and a maturity date of April 17, 2023, subject to a springing maturity on October 15, 2021 (see Note 9 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.
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:
•value driven development of our positions in the Delaware and Williston Basins;
•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 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;
•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 over the past five years. 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 $5.4 billion. In addition, the net book value associated with unproved leasehold is approximately $1.8 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
2018 vs. 2017
Revenue Analysis
__________
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:
•$911 million increase in oil sales reflects $501 million related to higher production sales volumes and $410 million related to higher sales prices for 2018 compared to 2017. The Delaware and Williston Basin volumes were 41.0 and 40.6 Mbbls per day, respectively, for 2018 compared to 22.0 and 30.0 Mbbls per day, respectively, for 2017. The following table reflects oil production prices, the price impact of our derivative settlements and volumes for 2018 and 2017.
__________
(a) Included in net gain (loss) on derivatives on the Consolidated Statements of Operations.
•$20 million increase in natural gas sales reflects $45 million related to higher production sales volumes offset by $25 million decrease related to lower gas sales prices for 2018 compared to 2017. The increase in our production sales volumes primarily relates to our Delaware Basin which had production volumes of 137.7 MMcf per day for 2018 compared to 78.2 MMcf per day for 2017. The following table reflects natural gas production prices, the price impact of our derivative settlements and volumes for 2018 and 2017.
__________
(a) Included in net gain (loss) on derivatives on the Consolidated Statements of Operations.
•$78 million increase in natural gas liquids sales primarily reflects $59 million related to higher production sales volumes and $18 million related to higher NGL sales prices for 2018 compared to 2017. The Delaware Basin volumes were 14.2 MBbls per day compared to 7.5 MBbls per day for 2018 and 2017, respectively. The Williston Basin volumes were 4.2 MBbls per day compared to 2.5 MBbls per day for 2018 and 2017, respectively. The following table reflects NGL production prices, the price impact of our derivative settlements and volumes for 2018 and 2017.
__________
(a) Included in net gain (loss) on derivatives on the Consolidated Statements of Operations.
•$78 million favorable change in net gain on derivatives primarily reflects changes in crude oil derivatives which were a result of decreases in 2018 of forward commodity prices relative to our hedge positions. Settlements to be paid on derivatives totaled $237 million for 2018 and settlements to be received totaled $4 million for 2017.
•$179 million increase in commodity management revenues primarily due to higher crude and natural gas sales volumes. A similar increase is reflected in the $155 million increase in related commodity management costs and expenses, discussed below. The increase in crude sales volumes is due to increased crude purchases to fulfill certain sales commitments. The increase in natural gas volumes resulted from the utilization of excess pipeline capacity we currently have in the Delaware Basin.
Cost and operating expense and operating income analysis:
__________
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:
•$235 million increase in depreciation, depletion and amortization is primarily due to higher production volumes partially offset by a $2.28 per Boe decrease in rate which was impacted by higher estimated reserves as compared to 2017 due to a higher 12-month average price, the addition of new wells with lower relative cost per Boe and an increase in Delaware production, which has a lower rate per Boe, relative to the overall total.
•$104 million increase in lease and facility operating expenses primarily related to the 63 percent increase in production volumes for 2018 compared to 2017.
•$83 million increase in gathering, processing and transportation is due in part to the adoption of ASU 2014-09, Revenue from Contracts with Customers, for which the net expense on certain transportation related arrangements that were recorded as a reduction in oil revenue in 2017 are included in gathering, processing and transportation in 2018 as well as the impact of the growth in production volumes in 2018.
•$78 million increase in taxes other than income related to increased product revenues, previously discussed.
•$12 million decrease in exploration expenses is primarily due to costs, recorded during first-quarter 2017, associated with certain expired leases in the Delaware Basin in excess of the accumulated amortization balance. See Note 5 of Notes to Consolidated Financial Statements.
•$16 million increase in general and administrative expenses for 2018 compared to 2017. Our general and administrative expenses per BOE decreased to an average $3.92 for 2018 compared to $5.80 for 2017.
•$155 million increase in commodity management expenses is primarily due to higher crude and natural gas purchase volumes as discussed above.
•The $161 net gain on sales of assets in 2017 primarily related to $103 million of gains on exchanges of leasehold acreage in the Delaware Basin and $48 million from recognition of deferred gains related to completion of commitments from a prior year disposition. See Note 5 of Notes to Consolidated Financial Statements for further discussion of these items.
Results below operating income
__________
NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.
The decrease in interest expense primarily relates to lower level of debt outstanding in 2018 compared to 2017.
In the second-quarter of 2018, we used proceeds from the San Juan Gallup disposition and proceeds from the issuance of$500 million 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 second-quarter 2018. See Note 9 of Notes to Consolidated Financial Statements for additional information regarding these transactions. In the third quarter of 2017, we issued $150 million of debt onto our 2024 Notes and extinguished $150 million of the 2020 Notes. As a result, we recorded a loss on extinguishment of debt of $17 million in 2017.
Income taxes for 2018 changed unfavorably compared to 2017 primarily due to pretax income in 2018 compared to a pre-tax loss from continuing operations in 2017. See Note 10 of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both periods. Our effective rate in future periods could be impacted by a valuation allowance on federal NOL carryovers (see Note 10 of Notes to Consolidated Financial Statements).
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. Loss from discontinued operations in 2017 primarily relates to a $60 million impairment of San Juan Legacy assets partially offset by operating results from the San Juan Basin. Other items in 2017 include accretion on the previously accrued liability for the contracts discussed below, partially offset by $10 million of severance tax refunds in the Piceance Basin related to prior years. See Note 3 of Notes to Consolidated Financial Statements for detail of amounts included in discontinued operations.
2017 vs. 2016
Revenue Analysis
__________
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:
•$428 million increase in oil sales reflects $239 million related to higher production sales volumes and $189 million related to higher sales prices for 2017 compared to 2016. The Delaware and Williston Basin volumes were 22.0 and 30.0 Mbbls per day, respectively, for 2017 compared to 13.0 and 20.8 Mbbls per day, respectively, for 2016. The following table reflects oil production prices, the price impact of our derivative settlements and volumes for 2017 and 2016.
__________
(a) Included in net gain (loss) on derivatives on the Consolidated Statements of Operations.
•$32 million increase in natural gas sales reflects $21 million related to higher sales prices and $11 million increase related to higher production sales volumes for 2017 compared to 2016. The increase in our production sales volumes occurred primarily in our Delaware Basin partially offset by the absence of volumes due to the sales of our natural gas producing properties in the Appalachian and Green River Basins. The following table reflects natural gas production prices, the price impact of our derivative settlements and volumes for 2017 and 2016.
__________
(a) Included in net gain (loss) on derivatives on the Consolidated Statements of Operations.
•$49 million increase in natural gas liquids sales is due to $36 million related to higher NGL sales prices and $13 million related to higher production sales volumes for 2017 compared to 2016. The increase in our production sales volumes is due to our Delaware Basin. The following table reflects NGL production prices and volumes for 2017 and 2016.
•$210 million favorable change in net gain (loss) on derivatives primarily reflects a favorable change from a loss of $207 million in 2016 to a gain of $3 million in 2017. Settlements from our derivatives totaled $4 million for 2017 and $302 million for 2016.
•$152 million decrease in commodity management revenues primarily due to lower natural gas sales volumes. Our volumes were higher in 2016 due in part to a short-term marketing agreement with the buyer of the Piceance Basin operations and the divestment of transportation contracts in the third quarter of 2016 that were related to our former Piceance Basin operations. A similar decrease is reflected in the $181 million decrease in related commodity management costs and expenses, discussed below.
Cost and operating expense and operating income (loss) analysis:
__________
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:
•$101 million increase in depreciation, depletion and amortization is due to increased production volumes partially offset by a $3.98 per Boe decrease in rate which was impacted by both an increase in the reserves due to an increase in the 12-month average price and the addition of new wells with lower relative cost per Boe.
•$50 million increase in lease and facility operating expenses primarily related to increased production volumes.
•$12 million increase in gathering, processing and transportation primarily due to higher volumes in the Delaware Basin.
•$36 million increase in taxes other than income primarily relates to increased product revenues.
•$61 million increase in exploration expenses is primarily due to unproved leasehold property impairment, amortization and expiration in 2017 which includes costs associated with certain expired leases in the Delaware Basin in excess of the accumulated amortization balance recorded during first-quarter 2017. These leases were renewed in second-quarter 2017. See Note 5 of Notes to Consolidated Financial Statements.
•$36 million decrease in general and administrative expenses primarily due to workforce reductions. In addition, 2016 included $15 million for severance and relocation costs associated with workforce reductions in third-quarter 2016 and office consolidations. Excluding the severance and relocation costs, total general and administrative expenses would have averaged $9.78 per Boe for 2016.
•$181 million decrease in commodity management expenses is primarily due to lower natural gas purchase volumes for 2017 compared to 2016. The higher volumes in 2016 were due in part to the marketing of the volumes for the purchaser of our Piceance Basin operations and the divestment of transportation contracts in the third quarter of 2016 that were related to our former Piceance Basin operations. Also included in commodity management expenses for 2016 is $27 million for unutilized pipeline capacity related to divested transportation contracts.
•$161 net gain on sales of assets in 2017 primarily related to $103 million of gains on exchanges of leasehold acreage in the Delaware Basin and $48 million from recognition of deferred gains related to completion of commitments from a prior year disposition. The $239 million net loss on sales of assets and divestment of transportation contracts in 2016 relates to the divestment of transportation obligations. See Note 5 of Notes to Consolidated Financial Statements for further discussion of these items.
Results below operating income (loss)
__________
NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.
The decrease in interest expense primarily relates to lower level of debt outstanding in 2017 compared to 2016.
In the third quarter of 2017, we issued $150 million of debt onto our 2024 Notes and extinguished $150 million of the 2020 Notes. As a result, we recorded a loss on extinguishment of debt of $17 million in 2017.
The benefit for income taxes for 2017 was less than the benefit in 2016 primarily due to lower pretax loss from continuing operations before income taxes in 2017 compared to 2016 offset by the $97 million impact to our net deferred tax liability of the enacted tax law change reducing the federal statutory rate from 35 percent to 21 percent. See Note 10 of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both periods.
Loss from discontinued operations in 2017 primarily relates to a $60 million impairment of San Juan Legacy assets partially offset by operating results from the San Juan Basin. Other items in 2017 include accretion on the previously accrued liability for the contracts discussed below, partially offset by $10 million of severance tax refunds in the Piceance Basin related to prior years. Income from discontinued operations in 2016 primarily related to activity from the San Juan Basin including the gain on the sale of the San Juan gathering system as well as activity from the Piceance Basin which was sold early in the second quarter of 2016. In conjunction with our exit from the Powder River Basin in 2015, we recorded a liability in 2015 related to retained future commitments under gathering, processing and transportation contracts in the Powder River Basin. In 2017, we increased the remaining liability for a change in estimate of third-party recoveries of future gathering and processing fees due to recent collectability issues. See Note 3 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 2019 are cash on hand, expected cash flows from operations, anticipated proceeds from the sales of non-core assets, 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 2019. 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 2019 capital expenditures:
•our planned capital expenditures, excluding acquisitions and equity investments, are estimated to be approximately $1.1 billion to $1.275 billion of which $1.050 billion to $1.175 billion relates to drilling and completions, including facilities; and
•we have hedged a portion of our anticipated 2019 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 and investment 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;
•lower than anticipated proceeds from asset sales;
•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 amended, includes total commitments of $1.5 billion, on a $2.0 billion Borrowing Base with a maturity date of April 17, 2023, subject to a springing maturity on October 15, 2021 if available liquidity minus outstanding 2022 notes is less than $500 million. Based on our current credit ratings, a Collateral Trigger Period applies which 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 9 of Notes to Consolidated Financial Statements. As of December 31, 2018, WPX had $330 million borrowings outstanding, had $52 million of letters of credit issued under the Credit Facility and was in compliance with our covenants under the credit agreement. Our unused borrowing availability was $1,118 million as of December 31, 2018.
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:
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 21, 2019 were as follows:
Sources (Uses) of Cash
Operating activities
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.
Net cash provided by operating activities increased in 2017 from 2016 primarily due to higher commodity prices and higher production volumes in 2017, partially offset by lower realizations on our derivatives and higher operating costs.
Excluding changes in working capital, total cash provided by operating activities related to discontinued operations was approximately $44 million, $143 million and $102 million for 2018, 2017 and 2016, respectively. Cash outflows related to previous accruals for Powder River Basin gathering and transportation contracts retained were $47 million, $53 million and $53 million for 2018, 2017 and 2016, respectively.
Investing activities
The table below includes cash and incurred capital expenditures for drilling and completions and capital expenditures for land acquisitions.
Significant components related to proceeds from the sale of our domestic assets and international interests are comprised of the following:
•$645 million of net proceeds from the sale of San Juan Gallup (see Note 3 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 3 of Notes to Consolidated Financial Statements).
•$862 million for the sale of WPX Energy Rocky Mountain, LLC that held our Piceance Basin operations to Terra Energy Partners, LLC (see Note 3 of Notes to Consolidated Financial Statements); and
•$280 million for the sale of our San Juan Basin gathering system during the first quarter of 2016 (see Note 3 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 Panther Acquisition.
Investing activities in 2017 includes net proceeds of $338 million from the formation of the joint venture with Howard (see Note 6 of Notes to Consolidated Financial Statements).
Cash provided by investing activities in 2016 was impacted by a $238 million divestment of certain transportation contracts (see Note 5 of Notes to Consolidated Financial Statements).
Financing activities
The following are significant financing activities by year:
•$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 9 of Notes to Consolidated Financial Statements for further discussion of our debt tender offers and debt issuance; and
•$330 million net borrowings on the Credit Facility.
•In January 2017, we completed an equity offering of 51.675 million shares for net proceeds of approximately $670 million in conjunction with the Panther Acquisition;
•$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.
•In June 2016, we completed an equity offering of 56.925 million shares of our common stock for net proceeds of approximately $538 million;
•net repayments under the Credit Facility of $265 million;
•$355 million repayment of our Senior Notes due 2017;
•$18 million of preferred stock dividends; and
•$10 million of cash paid as an inducement for the conversion of a portion of outstanding preferred stock to common stock.
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, 2018 and December 31, 2017. Although not a financing arrangement, we have provided a guarantee for certain obligations transferred as part of a divestment.
Contractual Obligations
The table below summarizes the maturity dates of our contractual obligations at December 31, 2018.
__________
(a) Includes materials and services obligations associated with our drilling rig contracts.
(b) Includes firm demand obligations of $44 million of which $40 million is recorded as a liability as of December 31, 2018. A liability was recorded in 2015 in conjunction with our exit from the Powder River Basin (see Note 3 of Notes to Consolidated Financial Statements). Excludes additional commitments totaling $123 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 which $24 million is recorded as a liability as of December 31, 2018. 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. Excluded are liabilities associated with asset retirement obligations totaling $72 million as of December 31, 2018. The ultimate settlement and timing of asset retirement obligations cannot be precisely determined in advance; however, we estimate that approximately 26 percent of this liability will be settled in the next five years.
(d) Obligations for financial derivatives are based on market information as of December 31, 2018, 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.
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 $69 million and $84 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 $1.8 billion at December 31, 2018 and is 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, 2018 did not identify any properties with a carrying value in excess of those estimated undiscounted cash flows. Therefore, no impairment charges were recorded in 2018 based on this assessment.
The assessments described above included approximately $5.4 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 over the past five years. 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 51 percent of our future production considered in the impairment assessment is in years 2024 and beyond. If the estimated commodity revenues (only one of the many estimates involved) of the predominately oil proved properties were lower by 20 to 30 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, capital loss carryovers 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, 2018, 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 requires judgment as our effective state deferred tax rate can change periodically based on changes in our operations. Our effective state deferred tax rate is based upon our current entity structure and the jurisdictions in which we operate.
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, 2018, 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.
At December 31, 2018, 99 percent of the fair value of our derivatives portfolio 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 $3 million of instruments included in Level 3 at December 31, 2018.
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 11 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, $529 million matures in 2022, $500 million matures in 2023, $650 million matures in 2024 and $500 million matures in 2026. Interest rates for each group are 6.00 percent, 8.25 percent, 5.25 percent and 5.75 percent, respectively. The aggregate fair value of the senior notes is $2,084 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, 2018, we had $330 million outstanding under the Credit Facility Agreement. See Note 9 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. See Notes 15 and 16 of Notes to Consolidated Financial Statements.
We measure the risk in our portfolios using a value-at-risk methodology to estimate the potential one-day loss from adverse changes in the fair value of the portfolios. Value at risk requires a number of key assumptions and is not necessarily representative of actual losses in fair value that could be incurred from the portfolios. Our value-at-risk model uses a Monte Carlo method to simulate hypothetical movements in future market prices and assumes that, as a result of changes in commodity prices, there is a 95 percent probability that the one-day loss in fair value of the portfolios will not exceed the value at risk. The simulation method uses historical correlations and market forward prices and volatilities. In applying the value-at-risk methodology, we do not consider that the simulated hypothetical movements affect the positions or would cause any potential liquidity issues, nor do we consider that changing the portfolios in response to market conditions could affect market prices and could take longer than a one-day holding period to execute. While a one-day holding period has historically been the industry standard, a longer holding period could more accurately represent the true market risk given market liquidity and our own credit and liquidity constraints.
We segregate our derivative contracts into trading and nontrading contracts, as defined in the following paragraphs. We calculate value at risk separately for these two categories. Contracts designated as normal purchases or sales and nonderivative energy contracts have been excluded from our estimation of value at risk.
We have policies and procedures that govern our trading and risk management activities. These policies cover authority and delegation thereof in addition to control requirements, authorized commodities and term and exposure limitations. Value-at-risk is limited in aggregate and calculated at a 95 percent confidence level.
Trading
We currently have entered into no other derivative contracts for purposes other than economically hedging our commodity price-risk exposure.
Nontrading
Our nontrading 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 asset of $141 million at December 31, 2018 and net liability of $177 million at December 31, 2017.
The value at risk for derivative contracts held for nontrading purposes was $26 million at December 31, 2018, and $56 million at December 31, 2017. During the year ended December 31, 2018, our value at risk for these contracts ranged from a high of $52 million to a low of $26 million. The decrease in value at risk from December 31, 2017 primarily reflects positions entered into to economically hedge our equity production being realized.
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, 2018, 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, 2018, 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, 2018, 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, 2018, 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, 2018 and 2017, 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, 2018, and the related notes and financial statement schedule listed in the Index at Item 15.(a) and our report dated February 21, 2019 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 21, 2019
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, 2018 and 2017, 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, 2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2018, 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 21, 2019 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.
/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2010.
Tulsa, Oklahoma
February 21, 2019
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, that include oil and natural gas purchased from third-party working interest owners in operated wells, the management of various commodity contracts, such as transportation and related derivatives, and the marketing of Piceance Basin volumes during a transition period from April 1, 2016 to June 30, 2016 (see Note 3).
We had operations in the San Juan Basin which were sold in 2017 and 2018 that are reported in discontinued operations as discussed below. We also had other operations sold in 2016 which are reported as 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
On January 30, 2018, we signed an agreement to sell our properties in the San Juan Basin’s Gallup oil play (“San Juan Gallup”) to Enduring Resources IV, LLC for $700 million (subject to closing and post-closing adjustments). This sale closed in March 2018. In December 2017, we sold our natural gas-producing properties in the San Juan Basin (“San Juan Legacy”) for $169 million, a portion of which closed in 2018. Collectively, the San Juan Gallup and San Juan Legacy comprised our San Juan Basin operations. Subsequent to the closing of these transactions, we no longer have operations in the San Juan Basin. The assets and liabilities were reclassified as held for sale on the Consolidated Balance Sheet as of December 31, 2017 and the results of operations of the San Juan Basin have been reclassified as discontinued operations on the Consolidated Statements of Operations (see Note 3).
Our discontinued operations also include the results of previously owned properties in the Piceance Basin.
See Note 3 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 which 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.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
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 $15 million and $12 million as of December 31, 2018 and 2017, respectively, and is included in other current assets on the Consolidated Balance Sheets.
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.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
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.
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.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
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.
The accounting for the changes in fair value of a commodity derivative can be summarized as follows:
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
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
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 or accounts payable, as appropriate. Our cumulative net oil and natural gas imbalance position based on market prices as of December 31, 2018 and 2017 was insignificant.
Commodity management expenses
Commodity management expenses primarily relate to product we may purchase from other third parties in the areas we operate. Charges for unutilized transportation capacity are included in commodity management expenses and were $27 million in 2016.
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 4).
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 $35 million and $32 million as of December 31, 2018 and 2017, respectively. Unamortized debt issuance costs related to the Company’s senior unsecured notes are reported in long-term debt (see Note 9) 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”) 2014-09, Revenue from Contracts with Customers, effective January 1, 2018 using the modified retrospective method. The core principle of the guidance in ASU 2014-09 is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The adoption of ASU 2014-09 was not material to our revenues or operating income (loss) or to our consolidated balance sheet because our performance obligations, which determine when and how revenue is recognized, are not materially changed under the new standard; thus, revenue associated with the majority of our contracts will continue to be recognized as control of products is transferred to the customer. A majority of the Company’s sales contracts at December 31, 2018 have terms of less than one year. For such contracts, we have used the practical expedient in ASC 606-10-50-14 which exempts an entity from the requirement to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract with an original expected duration of one year or less. For sales contracts with terms greater than one year, we have utilized the practical expedient in ASC 606-10-50-14A, which provides that an entity is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our sales contracts for all products, each unit of production represents a separate performance obligation that is satisfied upon delivery of product to the customer, thus, future volumes to be delivered are
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
wholly unsatisfied at the reporting period end. In addition, see Note 16 for receivables related to sales of oil, natural gas and related products and services.
We adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash, effective January 1, 2018 which requires entities to show the changes in the total of cash, cash equivalents, restricted cash and restricted cash equivalents in the statement of cash flows on a retrospective basis. The requirements of this standard are reflected on our Consolidated Statement of Cash Flows, including prior periods. Restricted cash was approximately $15 million, $12 million and $10 million as of December 31, 2018, 2017 and 2016, respectively.
We adopted ASU 2017-01, Business Combinations, clarifying the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses effective January 1, 2018.
We adopted ASU 2017-09, Compensation - Stock Compensation (Topic 718), effective January 1, 2018. This ASU provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting in Topic 718. The adoption of this standard did not have a significant impact on our consolidated financial statements.
Accounting Standards Not Yet Adopted
In February 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-02, Leases, to increase transparency and comparability among organizations through recognition of right-of-use assets and lease payment liabilities on the balance sheet and disclosure of key information about leasing arrangements. Under ASU 2016-02, a determination is to be 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. Only the lease components of a contract must be accounted for in accordance with this ASU. Non-lease components, such as activities that transfer a good or service to the customer, shall be accounted for under other applicable Topics. ASU 2016-02 permits lessees to make alternative policy elections (“practical expedients”) to not recognize right-of-use assets and lease payment liabilities for leases with terms of less than twelve months and/or to not separate lease and non-lease components and account for the non-lease components together with the lease components as a single lease component. Based on review of the guidance and the Company’s current commitments, the Company believes it will be required to recognize right-of-use assets and lease payment liabilities related to certain drilling rig commitments, certain equipment leases, and other arrangements. In 2018, we began the process of evaluating our contracts with components that may be subject to ASU 2016-02 and engaged a third party to assist with implementing the standard. In 2018 and 2019, we have implemented appropriate changes to our business processes, systems or controls to support recognition and disclosure under the new standard. Our findings and progress toward implementation of the standard are periodically reported to management. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. In July 2018, the FASB amended this guidance to ease the transition requirements by providing an adoption alternative that allows entities to recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption in lieu of retrospectively applying the guidance to pre-adoption periods. The Company is finalizing the impact of ASU 2016-02 to the Company’s Consolidated Financial Statements and related disclosures and the practical expedients we will utilize upon implementation of the standard. We believe the amounts recorded as right to use assets and lease payment liabilities will be less than $100 million.
In January 2018, the FASB issued ASU No. 2018-01, “Land Easement Practical Expedient for Transition to Topic 842,” which provides an optional practical expedient to exclude from evaluation any land easements that existed or expired before the adoption of ASU 2016-02 and that were not previously accounted for as leases under the original “Leases (Topic 840)” accounting standard (“Topic 840”). The Company enters into land easements on a routine basis as part of our ongoing operations and has many such agreements currently in place. The Company does not account for any land easements under Topic 840. As this guidance serves as an amendment to ASU 2016-02, the Company will elect this practical expedient, which becomes effective upon the date of adoption of ASU 2016-02. After the adoption of ASU 2016-02, the Company will assess any land easements entered into (or modified) on or after adoption of ASU 2016-02 to determine whether the arrangement should be accounted for as a lease.
In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses. The amendments affect trade receivables, financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with and expected loss model for instruments measured at amortized cost. This update is effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update 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 standard will have a material impact on the Company’s consolidated financial statements since the Company does not have a history of credit losses.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815). 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 assessment of effectiveness. The amendments in this ASU are effective for public entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2018. Early adoption is permitted, including adoption in any interim period. The Company does not expect any significant impact on its consolidated financial statements from the adoption of this standard unless we apply hedge accounting in a future period.
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 Update are effective for public entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2019. Early adoption is permitted, including adoption in any interim period. The Company does not expect any significant impact on its consolidated financial statements from the adoption of this standard.
Note 2. Acquisition
On January 12, 2017, we signed an agreement to acquire certain assets from Panther Energy Company II, LLC and Carrier Energy Partners, LLC (the “Panther Acquisition”) for $775 million, subject to post-closing adjustments. The transaction closed in March 2017 for $798 million including estimated closing adjustments. The assets, as of the closing date, included 25 producing wells (18 horizontals), three drilled but uncompleted horizontal laterals, approximately 18,000 net acres and more than 900 gross undeveloped locations in the Delaware Basin. We estimated that approximately $599 million of the purchase price is allocable to unproved properties and approximately $200 million is allocable to proved developed properties and facilities. This estimate is based on discounted cash flow models, which include estimates and assumptions such as future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk adjusted discount rates. These assumptions represent Level 3 inputs. At the time of the acquisition closing, production was approximately 10,000 Boe per day. The impact of this acquisition to prior periods is not material to our results of operations for those periods.
Note 3. Discontinued Operations
On January 30, 2018, we signed an agreement to sell our operations in the San Juan Basin’s Gallup oil play (“San Juan Gallup”) to Enduring Resources IV, LLC (“Enduring”) for $700 million (subject to closing and post-closing adjustments). The transaction closed on March 28, 2018 and we received approximately $667 million (subject to post-closing adjustments). In addition, the purchaser assumed approximately $309 million of gathering and processing commitments; however, WPX has left in place a performance guarantee with respect to these commitments. We 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 Enduring and the declining size of the obligations subject to the guarantee over time. Although we believe the probability of performance by WPX is low, we must determine 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. The operations in the San Juan Gallup represented 12 percent of our total proved reserves at December 31, 2017 and 16 percent of our total production for 2017.
In December 2017, we sold our natural gas-producing properties in the San Juan Basin (“San Juan Legacy”) for $169 million and recorded a gain of approximately $2 million. A portion of the San Juan Legacy sale closed in 2018. Collectively, the San Juan Gallup and San Juan Legacy comprised our San Juan Basin operations. Subsequent to the closing of these transactions, we no longer have operations in the San Juan Basin.
Significant transactions for the San Juan Basin operations reflected in the tables below are as follows:
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
•In the third quarter of 2017, we began a process to market our San Juan Legacy properties 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 at September 30, 2017 which resulted in an impairment of $60 million recorded in third-quarter 2017. At the close of the sale, we recorded a gain of $2 million.
•On March 9, 2016, we completed the sale of our San Juan Basin gathering system for consideration of approximately $309 million. The consideration reflected $285 million in cash, subject to closing adjustments, and a commitment estimated at $24 million in capital designated by the purchaser to expand the system to support WPX’s development in the Gallup oil play. We were obligated to complete certain in-progress construction as of the closing which resulted in the deferral of a portion of the gain. As a result of this transaction, we recorded a gain of $199 million in first-quarter 2016 and additional gains of $18 million in the subsequent quarters of 2016 as certain in-progress construction was completed. As of December 31, 2017, the remaining deferred gain was approximately $3 million.
On February 8, 2016, we signed an agreement with Terra Energy Partners LLC (“Terra”) to sell WPX Energy Rocky Mountain, LLC that held our Piceance Basin operations for $910 million. The agreement also required Terra to become financially responsible for approximately $104 million in transportation obligations held by our marketing company. Additionally, WPX Energy Rocky Mountain LLC had natural gas derivatives with a fair value of $48 million as of the closing date. The parties closed this sale in April of 2016 and we received net proceeds of $862 million, subject to post-closing adjustments, resulting in a gain of $52 million. We performed certain transition services for the buyer which concluded during third-quarter 2016. In addition, we had an agreement with the buyer to purchase production through June 30, 2016 which is reported in commodity management revenue and expenses.
We sold our Powder River Basin properties in 2015; however, we retained certain firm gathering and treating obligations that continue through 2020 related to the Powder River properties sold. These commitments had been in excess of the production throughput. At the time of closing, we also had certain pipeline capacity obligations held by our marketing company that continue through 2021. We recorded liabilities related to these commitments in 2015. In 2017, we increased the liability for a change in estimate of third-party recoveries of future gathering and processing fees due to recent collectability issues. See Note 11 for additional information related to these liabilities.
Summarized Results of Discontinued Operations
The following table presents the results of discontinued operations for the years presented.
__________
(a) Includes severance tax refund received in 2017.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Assets and Liabilities in the Consolidated Balance Sheets Attributable to Discontinued Operations
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 $47 million, $53 million and $53 million for 2018, 2017 and 2016, respectively. During 2017, we received a $10 million severance tax refund for prior years related to our former Piceance Basin operations.
__________
(a) Excluding income taxes and changes to working capital.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Note 4. Earnings (Loss) Per Common Share from Continuing Operations
The following table summarizes the calculation of earnings per share.
__________
(a) Certain amounts are excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to (i) a loss from continuing operations attributable to WPX Energy, Inc. available to common stockholders; (ii) application of the if-converted method to common shares issuable upon assumed conversion of convertible preferred stock; or (iii) application of the treasury stock method to certain nonvested restricted stock units. The excluded amounts are as follows:
The table below includes information related to stock options that were outstanding at December 31, 2018, 2017 and 2016 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.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Note 5. Asset Sales and Exploration Expenses
Asset Sales
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 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.
During July 2016, we completed the divestment of the remaining transportation contracts primarily related to our Piceance Basin operations which eliminated certain pipeline capacity obligations held by our marketing company, which were not included in the Piceance Basin divestment. As a result of the divestment and net payment of $238 million, we recorded a net loss of $238 million in third-quarter 2016.
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.
Note 6. Investments
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 newly formed joint venture legal entity, Catalyst Midstream Partners LLC (“Catalyst”) and a Howard entity will serve as operator. In addition to a $300 million cash contribution, Howard is obligated to fund the first $263 million of joint venture capital expenditures. At closing in October 2017, WPX contributed subsidiaries holding crude oil gathering and natural gas processing assets already in service and/or under construction, with a net book value of approximately $53 million. WPX also paid $11 million for advisory services and legal fees on the transaction. Howard contributed $439 million in cash at closing, $139 million of which applies to the $263 million carry obligation of Howard including $49 million for capital expenditures from January 1, 2017 to closing. Concurrently, WPX received a $300 million special distribution plus the $49 million for capital expenditures from Catalyst. We will account for our investment in Catalyst as an equity method investment. In connection with the joint venture, 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 $58 million and $64 million as of December 31, 2018 and 2017, respectively. In 2017, we deferred recognition of the $349 million 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, 2018, the deferred amount was $346 million of which $336 million is reported within other noncurrent liabilities on the Consolidated Balance Sheet.
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.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Note 7. Properties and Equipment
Properties and equipment is carried at cost and consists of the following:
__________
(a) Estimated useful lives are presented as of December 31, 2018.
(b) Proved properties are depreciated, depleted and amortized using the units-of-production method (see Note 1).
(c) Unproved properties and construction in progress are not yet subject to depreciation and depletion.
Unproved properties consist primarily of non-producing leasehold in the Delaware Basin.
In December 2018, we signed an agreement to sell certain non-core properties in the Delaware Basin. These properties are reflected in assets classified as held for sale on the Consolidated Balance Sheet for December 31, 2018 (see Note 17).
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 2018 and 2017 is presented below.
__________
(a) Accretion expense is included in lease and facility operating expense on the Consolidated Statements of Operations.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Note 8. 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 9. Debt and Banking Arrangements
The following table presents a summary of our debt as of the dates indicated below.
__________
(a) Interest paid on debt totaled $157 million, $178 million and $194 million for 2018, 2017 and 2016, respectively.
(b) Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Credit Facility
On April 17, 2018, the Company entered into a Second 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, increases total commitments to $1.5 billion, increases the Borrowing Base to $1.8 billion, and extends the maturity date to April 17, 2023, subject to a springing maturity on October 15, 2021 if available liquidity minus outstanding 2022 notes is less than $500 million. Based on our current credit ratings, a Collateral Trigger Period applies which 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, 2018, WPX had $330 million borrowings outstanding, had $52 million of letters of credit issued under the Credit Facility and was in compliance with our covenants under the credit agreement.
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 October 2018, the Borrowing Base was increased to $2.0 billion and will remain in effect until the next Redetermination Date as set forth in the Credit Facility. At this time, the Credit Facility Agreement is limited by the total commitments on the Credit Facility which remained at $1.5 billion. The Borrowing Base is recalculated at least every six months per the terms of the Credit Facility.
Terms and Conditions. The Credit Facility will initially be 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 obligations 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,
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
among other things, the ability of the Company’s subsidiaries to incur indebtedness; the ability of the Company 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, 2018.
__________
(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 a redemption price equal to 100% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest thereon to the redemption date as more fully described in the indenture.
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.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
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.
During third-quarter 2017, we issued an additional $150 million of our 5.250% senior notes due 2024. The proceeds were used to fund the tender offer of $150 million of our 7.500% senior notes due 2020. As a result, we recorded a loss on extinguishment of debt of $17 million.
The terms of the indentures governing our 2022 Notes, 2023 Notes, 2024 Notes and 2026 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.
Note 10. Provision (Benefit) for Income Taxes
The following table includes the provision (benefit) for income taxes from continuing operations.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
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 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 recorded a current receivable of $38 million as of December 31, 2018 related to AMT credit refunds expected to be collected in 2019. 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.
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. As a result of the sale of our Piceance Basin operations in Colorado in the second quarter of 2016, we recorded $8 million of valuation allowances against Colorado NOL and credit carryovers generated in prior years.
Significant changes to our operations during 2018, 2017 and 2016 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 $5 million and $12 million deferred tax benefit in 2018 and 2017, respectively. We also accrued an additional $15 million of deferred tax expense in 2016.
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 be recorded as they were identified during the one-year measurement period as provided for in SAB 118. Accordingly, the Company did not have any adjustments to its provisional amounts.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
The following table includes significant components of deferred tax liabilities and deferred tax assets.
Net cash payments (refunds) for income taxes were $2 million, $(39) million and $21 million in 2018, 2017 and 2016, respectively.
The Company has federal NOL carryovers of approximately $2,021 million at December 31, 2018, including a $353 million NOL acquired in 2015 ("RKI NOL"), that will not begin to expire until 2032. In addition, we have $48 million of federal capital loss carryovers at December 31, 2018, that will begin to expire in 2020.
The Company has state NOL carryovers of approximately $4.1 billion and $3.8 billion at 2018 and 2017, 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 as well as our federal capital loss carryover. 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, 2018, 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 or minimum tax credits 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, 2018, 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 alternative minimum tax credit deferred tax asset that was 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
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
expected to result in a cash settlement with Williams. However, if the Company has to amend filed returns whereby a refund of AMT credits are received, the Company may have to remit cash to the IRS.
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 2016 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 less than $1 million for 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, 2018, the Company has approximately $8 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 will result in a significant increase or decrease of an unrecognized tax benefit.
Note 11. Contingent Liabilities and Commitments
Contingent Liabilities
Royalty litigation
In October 2011, a potential class of royalty interest owners in New Mexico and Colorado filed a complaint against us in the County of Rio Arriba, New Mexico. The complaint presently alleges failure to pay royalty on hydrocarbons including drip condensate, breach of the duty of good faith and fair dealing, fraudulent concealment, conversion, misstatement of the value of gas and affiliated sales, breach of duty to market hydrocarbons in Colorado, breach of implied duty to market, violation of the New Mexico Oil and Gas Proceeds Payment Act, and bad faith breach of contract. Plaintiffs sought monetary damages and a declaratory judgment enjoining activities relating to production, payments and future reporting. This matter was removed to the United States District Court for New Mexico where the court denied plaintiffs’ motion for class certification. In March 2017, plaintiffs appealed the denial of class certification to the Tenth Circuit and on September 21, 2018 the Tenth Circuit dismissed the appeal for lack of jurisdiction. On January 22, 2019, plaintiffs’ filed a petition for certiorari to the United States Supreme Court. At this time, we believe that our royalty calculations were properly determined in accordance with the appropriate contractual arrangements and applicable laws. We do not have sufficient information to calculate an estimated range of exposure related to these claims.
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 recently 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 Environmental Protection Agency (“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.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
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 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. On October 23, 2018, a settlement in principle with the Kansas and Missouri class claimants was reached. Final documents have not been finalized and approved by the Court. In the Wisconsin class action, defendants’ motion for entry of their proposed order denying class certification remains pending, along with the plaintiffs’ motion to remand the case to the originally filed district court.
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. The parties have filed numerous motions for summary judgment, reconsideration and remand. 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.
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 took transportation costs into account when calculating royalty payments. In 2017, we settled one of these claims.
As of December 31, 2018, 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
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
indemnify and hold us harmless from any losses resulting from the operation of its business or arising out of liabilities assumed by it.
Summary
As of December 31, 2018 and December 31, 2017, the Company had accrued approximately $11 million 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. During 2017 and 2018, we entered into various contracts for pipeline capacity to move our Permian Basin production to market. 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, 2018, 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.
Future minimum annual rentals under noncancelable operating leases as of December 31, 2018, are payable as follows:
Total rent expense, excluding amounts capitalized, was $25 million, $19 million and $23 million in 2018, 2017 and 2016, 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 12. Employee Benefit Plans
WPX has a defined contribution plan which matches 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
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
older and 6 percent of eligible pay if they are under age 40. Total contributions to this plan were $10 million, $11 million and $13 million for 2018, 2017 and 2016, respectively. Approximately $7 million was included in accrued and other current liabilities at both December 31, 2018, and 2017 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, 2018, 18 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 12 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 $32 million, $28 million and $31 million for of the years ended December 31, 2018, 2017 and 2016, 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, 2018 was $40 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, 2018.
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 97 thousand shares at an average price of $10.74 per share during 2018.
Nonvested Restricted Stock Units and Awards
The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2018.
__________
(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
Performance-based shares granted represent 36 percent of nonvested restricted stock units outstanding at December 31, 2018. 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.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
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, 2018.
The total intrinsic value of options exercised was $4.3 million, $224 thousand and $160 thousand for the years ended December 31, 2018, 2017 and 2016, respectively.
Cash received from stock option exercises was $9.2 million, $0.4 million and $0.4 million during 2018, 2017 and 2016, respectively.
The Company did not grant stock options during the years ended 2018, 2017 and 2016.
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.
Series A Mandatory Convertible Preferred Stock
On July 22, 2015, we issued 7 million shares, $0.01 par value, pursuant to a registered public offering, of our Preferred Stock at $50 per share, for gross proceeds of approximately $350 million, before underwriting discounts and commissions. Dividends on our Preferred Stock were paid in cash on January 31, April 30, July 31 and October 31 of each year, commencing on October 31, 2015 and ending on, and including, July 31, 2018.
On July 20, 2016, we entered into Conversion Agreements with certain existing beneficial owners (the “Preferred Holders”) of our Preferred Stock, pursuant to which each of the Preferred Holders agreed to convert (the “Conversion”) shares of Preferred Stock it beneficially owned into shares of our common stock, par value $0.01 per share, and in addition receive a cash payment from us in connection with the Conversion. The Preferred Holders agreed to convert an aggregate of approximately 2.2 million shares of Preferred Stock into approximately 10.2 million shares of our common stock in the Conversion, and we made an aggregate cash payment to the Preferred Holders of approximately $10 million. Following the Conversion, approximately 4.8 million shares of Preferred Stock remain outstanding. We issued the shares of common stock in the Conversion on July 28, 2016. As a result of the cash payment and additional shares issued as an inducement to the Preferred Holders, we recorded a loss of $22 million in 2016.
On July 30, 2018, all of the outstanding shares, approximately 4.8 million, of our preferred stock converted into approximately 19.8 million shares of our common stock pursuant to the mandatory conversion provisions of the preferred stock offering.
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
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
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 2018, 2017 or 2016. 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.
On June 6, 2016, we completed an underwritten public offering of 56.925 million shares of our common stock, which included 7.425 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 $9.47 per share and we received proceeds of approximately $538 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.
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 the Panther Acquisition (see Note 2).
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.
•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.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
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, restricted cash and margin deposits approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.
__________
(a) The carrying value of total debt, excluding capital leases and debt issuance costs, was $2,509 million and $2,600 million as of December 31, 2018 and 2017, 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 and 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 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.
Exchange-traded contracts include New York Mercantile Exchange and Intercontinental Exchange contracts and are valued based on quoted prices in these active markets and are classified within Level 1.
Forward, swap, option and swaption contracts included in Level 2 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 costless collars, calls 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 several crude oil and natural gas swaps entered into, we granted swaptions and calls to the swap counterparties in exchange for receiving premium hedged prices on the crude oil and natural gas swaps. These swaptions and calls grant the counterparty the option to enter into future swaps with us. 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 exchange-traded 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 within Level 3 when these inputs have a significant impact on the measurement of fair value. We had instruments totaling $3 million included in Level 3 as of December 31, 2018. There were no instruments included in Level 3 as of December 31, 2017.
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, 2018 or 2017.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
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 5 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 3 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.
WPX Energy, Inc.
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, 2018.
__________
(a) Derivatives related to crude oil production are fixed price swaps settled on the business day average, basis swaps, fixed price calls and 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.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
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.
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.
__________
(a) Includes payments totaling $237 million for the year ended December 31, 2018 and settlements totaling $4 million and $301 million for the years ended December 31, 2017 and 2016, respectively.
(b) Includes payments totaling less than $1 million for the years ended December 31, 2018 and 2017 and settlements totaling $1 million for the year ended December 31, 2016.
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.
__________
(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
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
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, 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 less than $1 million to our liability balance for our own nonperformance risk. As of December 31, 2017, we did not have any collateral posted to derivative counterparties to support the aggregate fair value of our net $194 million derivative liability position (reflecting master netting arrangements in place with certain counterparties) which includes a reduction of $4 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 less than $1 million and $194 million at December 31, 2018 and 2017, respectively.
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 2018, 2017 and 2016, 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.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Our gross and net credit exposure from our derivative contracts were $178 million and $141 million, respectively, as of December 31, 2018. 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 six largest net counterparty positions represent approximately 91 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, 2018, we held collateral support of $10 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.
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 NGL Energy. For the year ended 2018, sales to NGL Energy were approximately 14 percent of our total consolidated revenues adjusted for gain (loss) on derivatives. In addition, a subsidiary of NGL Energy provides water disposal services for WPX that represent less than 1 percent of operating expenses.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Note 17. Subsequent Events
We have signed agreements to divest certain holdings for aggregate proceeds in excess of $200 million. The agreements consist of separate sales transactions for our 20 percent equity interest in the Whitewater natural gas pipeline which we expect to close in first-quarter 2019 and roughly 5,600 net acres in the Delaware Basin which has closed in 2019. We have also closed on a $100 million purchase of 14,000 surface acres within our Stateline operations, which we expect will provide economic benefit through speed of development, facilitation of longer laterals, right of way access and revenue associated with infrastructure like roads, water and electricity.
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 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 3).
Second-quarter 2018:
•$71 million loss on extinguishment of debt (see Note 9).
First-quarter 2017:
•$31 million net gain on sales of assets and exchanges of leasehold acreage and deferred gains related to the completion of commitments from the sales of gathering systems in prior years (see Note 5).
•$23 million loss on write-off of expired leases in the Permian Basin (see Note 5).
Third-quarter 2017:
•$111 million net gain on sales of assets and exchanges of leasehold acreage and deferred gains related to the completion of commitments from the sales of gathering systems in prior years (see Note 5).
•$60 million impairment on San Juan Legacy included in discontinued operations (see Note 3).
•$17 million loss on extinguishment of debt (see Note 9).
•$10 million severance tax refunds for prior years related to the Piceance Basin (see Note 3).
Fourth-quarter 2017:
•$11 million gain on leasehold exchanges (see Note 5).
•$5 million increase on future commitments under gathering, processing and transportation liability related to the Powder River Basin in discontinued operations (see Note 3).
•$92 million income tax benefit related to the impact of new income tax legislation (see Note 10).
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.
With the exception of Capitalized Costs, the following information includes activity through the completion of the respective asset sales. These sales include operations which are reported within continuing operations and the operations of the San Juan and Piceance Basins, both of 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. The Piceance Basin properties were sold in April 2016. Capitalized Costs do not include amounts which are classified as assets held for sale on the Consolidated Balance Sheets.
Capitalized Costs
__________
•Excluded from capitalized costs are equipment and facilities in support of oil and gas production of $276 million and $223 million, net, as of December 31, 2018 and 2017, 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.
•Acquisition costs are as follows: 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 (see Note 2 of Notes to Consolidated Financial Statements) in March 2017 that included $195 million and 23.8 MMboe of proved developed reserves and facilities. Costs in 2016 primarily relates to purchases of additional acreage in the Delaware Basin and included approximately 2.5 MMboe of proved reserves.
•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 and Piceance Basin operations were $24 million, $168 million and $102 million for 2018, 2017 and 2016, 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 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. Revisions in 2016 primarily reflect 49 MMboe of negative revisions due to the decrease in the 12-month average price partially offset by 34 MMboe of positive revisions due to decreased costs and well improvements.
•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. Divestitures in 2016 relate to the sale of the Piceance Basin which included proved developed reserves and proved undeveloped reserves of 222 MMboe and 67 MMboe, respectively.
•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. Extensions and discoveries in 2016 reflect 26 MMboe added for proved developed locations and 84 MMboe for proved undeveloped locations primarily in the Delaware Basin.
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, 2018, 2017 and 2016 was $61.57, $46.39 and $35.91 per barrel, respectively. The average natural gas price used in the estimates for the years ended December 31, 2018, 2017 and 2016 was $1.21, $1.67 and $1.74 per Mcf, respectively. The average NGL price per barrel was $26.76, $21.16 and $10.57 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 assets with a portion included in assets held for sale.
(c) Deducted from related liabilities.
(d) Included in revenues.
(e) 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 2018 Changes in Internal Controls
There have been no changes during the fourth quarter of 2018 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 2019 Annual meeting of Stockholders, or our 2019 Proxy Statement, anticipated to be filed with the Securities and Exchange Commission within 120 days of December 31, 2018, 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 2019 Proxy Statement anticipated to be filed with the Securities and Exchange Commission within 120 days of December 31, 2018, 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 2019 Proxy Statement anticipated to be filed with the Securities and Exchange Commission within 120 days of December 31, 2018, 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 2019 Proxy Statement anticipated to be filed with the Securities and Exchange Commission within 120 days of December 31, 2018, 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 21, 2019
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.