WPX ENERGY, INC. 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 theDelaware Basin inTexas andNew Mexico and theWilliston Basin inNorth Dakota . Associated with our commodity production are sales and marketing activities, which include oil and natural gas purchased from third- party working interest owners in operated wells and the management of various commodity contracts such as transportation. The revenues and expenses related to these sales and marketing activities are reported on a gross basis as part of commodity management revenues and costs and expenses. In late 2017 and early 2018, we divested our natural gas and oil properties in theSan Juan Basin through two separate transactions. Subsequent to the closing of these transactions, we no longer have operations in theSan Juan Basin . For all periods presented, the results of theSan Juan Basin are reported as discontinued operations. See Note 2 of Notes to Consolidated Financial Statements for further discussion of our discontinued operations. Unless indicated otherwise, the following discussion relates to continuing operations. The following discussion should be read in conjunction with the selected historical consolidated financial data and the consolidated financial statements and the related notes in Part II, Item 8, Financial Statements and Supplemental Data of this Form 10-K. See the Company's Annual Report on Form 10-K for the year endedDecember 31, 2018 for a discussion of the Company's 2018 results of operations as compared to the Company's 2017 results of operations. The matters discussed below may contain forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to these differences include, but are not limited to, those discussed below and elsewhere in this 10-K, particularly in "Risk Factors" and "Forward-Looking Statements." 46 --------------------------------------------------------------------------------
Overview
Composition of Production (based on Mboe) and Product Revenue
Years Ended December 31 ,
Production Product Revenue
[[Image Removed: wpx-20191231_g4.jpg]]The following table presents our production volumes and financial highlights for 2019, 2018 and 2017:
Years Ended December 31,
2019 2018 2017
Production Sales Volume Data(a): Per day Per day Per day
Oil (Mbbls) 37,822 103.6 29,769 81.6 18,964 52.0
Natural gas (MMcf) 78,354 214.7 59,365 162.6 35,311 96.7
NGLs (Mbbls) 10,043 27.5 6,733 18.4 3,656 10.0
Combined equivalent volumes (Mboe) 60,924 166.9 46,396 127.1 28,505 78.1
Financial Data (millions):
Total product revenues $ 2,247 $ 2,025 $ 1,016
Total revenues $ 2,292 $ 2,310 $ 1,045
Operating income $ 144 $ 554 $ 98
Capital expenditure activity(b) $ (1,313) $ (1,510) $ (1,232) __________
(a) Excludes production from our discontinued operations.
(b) Includes capital expenditures related to discontinued operations of
Our 2019 operating results were$410 million unfavorable compared to 2018. The primary items impacting 2019 results compared to 2018 results include: •$234 million unfavorable change in net gain (loss) on derivatives; and •$350 million higher operating costs including depreciation, depletion and amortization, lease and facility, gathering, processing and transportation, and taxes other than income. 47 -------------------------------------------------------------------------------- Offset by: •$222 million increase in product revenues, primarily oil sales. Overall,$584 million related to higher production sales volumes substantially offset by$362 million related to lower sales prices. Outlook After our multi-year transformation of WPX, our oil-prone positions in theDelaware (Permian) and Williston Basins now form the foundation of WPX. Our acreage positions in each of these basins contains some of the premier geology in the plays and inNorth America . Over the same period, we also assembled an attractive infrastructure portfolio in the Permian, which will help flow our production out of the basin and will create additional value either through monetization of our midstream investments or lower operating costs. In addition to our joint venture withHoward Energy Partners LLC , we made additional investments during 2018 in our equity positions in two companies that own pipeline systems in theDelaware Basin . In 2019, we closed on transactions and monetized the value in those equity positions totaling approximately$500 million and utilized those proceeds to reduce debt. In addition to these monetizations and debt reduction, WPX took other steps to enhance its value proposition, including launching a share buyback program, generating free cash flow and lowering our weighted-average interest rate on long-term debt. In the latter half of 2019, we communicated a vision for the Company, which included, among other items, implementing a meaningful dividend, targeting a 7% to 10% free cash flow yield and driving down our leverage metric from current levels. Our focus is, in part, on the important metrics that will drive investor interest over the next 5 years and allow us to compete against any sector, not just energy. InDecember 2019 , we entered into an agreement withFelix Investments Holdings II, LLC ("Felix Parent") to acquire all of the issued and outstanding membership interests ofFelix Energy Holdings II, LLC , or Felix (collectively, the "Felix Acquisition"), for consideration of approximately$2.5 billion ("Purchase Price"), consisting of$900 million in cash (such amount the "Unadjusted Cash Purchase Price") and 152,963,671 unregistered shares of our common stock determined by dividing$1.6 billion by$10.46 (the volume weighted-average price per share price of the Company for the ten consecutive days ending onDecember 13, 2019 ) (the "Unadjusted Equity Consideration"). The Purchase Price is subject to customary closing adjustments. See Note 17 of Notes to Consolidated Financial Statements for further discussion of the Felix Acquisition. The Felix Acquisition is consistent with the tenets in our 5-year vision and will allow us to accomplish these objectives more quickly and efficiently thru this highly de-risked, leverage neutral transaction. We plan to implement a dividend following the integration of Felix, targeting approximately$0.10 per share on an annualized basis at initiation. To fund the cash portion of the Felix Acquisition, we completed aJanuary 2020 offering of$900 million of 4.50% Senior Notes due in 2030, the proceeds of which are held in escrow until the closing of the Felix Acquisition. Our expected base full-year 2020 capital budget, including the impact of the Felix Acquisition assuming a late first quarter or early second quarter closing and excluding land purchases, is$1.675 billion to$1.8 billion . Planned capital for drilling and completions, including non-operated wells, is$1.625 billion to$1.725 billion for the full year 2020, with an additional$50 million to$75 million in midstream opportunities in theDelaware Basin . Our liquidity atDecember 31, 2019 totaled approximately$1.5 billion , reflecting amounts available under the Credit Facility Agreement and cash on hand. Our next Senior Note maturity of$73 million is not due until 2022. As of this filing and before consideration of the Felix Acquisition, our Credit Facility Agreement is subject to a$2.1 billion borrowing base with aggregate elected commitments of$1.5 billion and a maturity date ofApril 17, 2023 (see Note 8 of Notes to Consolidated Financial Statements for further discussion). We believe our current liquidity position will provide the necessary capital to develop our assets or should sustain us if there is a downturn. Overall, we believe we are well positioned for prudent and disciplined growth assuming a constructive commodity price environment. However, the challenging and dynamic environment of the oil and gas industry, along with future market conditions, may alter these expectations or plans. If we foresee other-than-temporary changes in market conditions, including significant fluctuation in expected commodity prices, we will evaluate the appropriateness of adjustments to our plans. As we execute on our long-term strategy, we continue to operate with a focus on increasing shareholder value and investing in our businesses in a way that enhances our competitive position by: •sustainable, value driven and environmentally responsible development of our positions in theDelaware and Williston Basins; •successful integration of Felix; •continuing to pursue cost improvements and efficiency gains; •employing new technology and operating methods; •continuing to invest in projects to assess resources and add new development opportunities or opportunistic acquisitions to our portfolio; 48 -------------------------------------------------------------------------------- •retaining the flexibility to make adjustments to our planned levels and allocation of capital investment expenditures in response to changes in economic conditions or business opportunities; and •continuing to maintain an active economic hedging program around our commodity price risks. Potential risks or obstacles that could impact the execution of our plan include: •lower than anticipated energy commodity prices; •inability to successfully integrate Felix's operations or to realize cost savings, revenues or other anticipated benefits of the Felix Acquisition; •increase in the cost of, or shortages or delays in the availability of, drilling rigs and equipment supplies, skilled labor or transportation; •higher capital costs of developing our properties, including the impact of inflation; •lower than expected levels of cash flow from operations; •counterparty credit and performance risk; •general economic, financial markets or industry downturn; •unavailability of capital either under our revolver or access to capital markets; •changes in the political and regulatory environments; and •decreased drilling success. We continue to address certain of these risks through utilization of commodity hedging strategies, disciplined investment strategies and maintaining adequate liquidity. In addition, we use master netting agreements and collateral requirements with our counterparties to reduce credit risk and liquidity requirements. Further, we continue to monitor the long-term market outlooks and forecasts for potential indicators of needed changes to our forecasted oil and natural gas prices. Commodity prices are volatile and prices for a barrel of oil ranged from over$100 per barrel to less than$30 per barrel since 2014. Our forecasted price assumptions reflect a long-term view of pricing but also consider current prices and are consistent with pricing assumptions generally used in evaluating our drilling decisions and acquisition plans. If forecasted oil and natural gas prices were to decline, we would need to review the producing properties net book value for possible impairment. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges will be recorded. If impairments were required, the charges could be significant. The net book value of our proved properties is$5.9 billion . In addition, the net book value associated with unproved leasehold is approximately$1.6 billion and is primarily associated with ourDelaware Basin properties. See our discussion of impairment of long-lived assets in our Critical Accounting Estimates discussion later in this section. Results of Operations 2019 vs. 2018 Revenue Analysis Years ended December 31, Favorable Favorable (Unfavorable) (Unfavorable) % 2019 2018 $ Change Change (Millions) Revenues: Oil sales$ 2,050 $ 1,790 $ 260 15 % Natural gas sales 75 87 (12) (14) % Natural gas liquid sales 122 148 (26) (18) % Total product revenues 2,247 2,025 222 11 % Net gain (loss) on derivatives (153) 81 (234) NM Commodity management 194 204 (10) (5) % Other 4 - 4 NM Total revenues$ 2,292 $ 2,310 $ (18) (1) % __________
NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.
49
--------------------------------------------------------------------------------
Significant variances in the respective line items of revenues are comprised of
the following:
•$260 million increase in oil sales reflects $485 million related to higher
production sales volumes partially offset by $225 million related to lower sales
prices for 2019 compared to 2018. The increase in production sales volumes was
primarily driven by our Williston Basin . The Williston Basin volumes increased
41 percent to 57.2 MBbls per day from 40.6 MBbls per day for 2019 and 2018,
respectively. The Delaware Basin volumes increased 13 percent to 46.4 MBbls per
day from 41.0 MBbls per day for 2019 and 2018, respectively. The following table
reflects oil production prices, the price impact of our derivative settlements
and volumes for 2019 and 2018.
Years ended December 31,
2019 2018
Oil sales (per barrel) $ 54.20 $ 60.14 Impact of net cash paid related to settlement of derivatives (per barrel)(a)
(1.14) (8.56)
Oil net price including all derivative settlements (per barrel) $
53.06 $ 51.58
Oil production sales volumes (Mbbls) 37,822 29,769
Per day oil production sales volumes (Mbbls/d) 103.6 81.6
__________
(a) Included in net gain (loss) on derivatives on the Consolidated Statements of Operations. •$12 million decrease in natural gas sales reflects$39 million decrease related to lower gas sales prices for 2019 compared to 2018, partially offset by$27 million increase related to higher production sales volumes for 2019 compared to 2018. The increase in our production sales volumes primarily relates to ourDelaware Basin , which had production volumes of 173.0 MMcf per day for 2019 compared to 137.7 MMcf per day for 2018. The following table reflects natural gas production prices, the price impact of our derivative settlements and volumes for 2019 and 2018. Years ended December 31, 2019 2018 Natural gas sales (per Mcf)$ 0.96 $ 1.46
Impact of net cash received related to settlement of derivatives (per Mcf)(a)
0.70 0.51
Natural gas net price including all derivative settlements (per Mcf) $
1.66 $ 1.97
Natural gas production sales volumes (MMcf) 78,354 59,365
Per day natural gas production sales volumes (MMcf/d) 214.7 162.6
__________
(a) Included in net gain (loss) on derivatives on the Consolidated Statements of Operations.
50
--------------------------------------------------------------------------------
•$26 million decrease in natural gas liquids sales primarily reflects $99
million related to lower NGL sales prices partially offset by $73 million
related to higher production sales volumes for 2019 compared to 2018. The
Delaware Basin volumes were 20.8 MBbls per day compared to 14.2 MBbls per day
for 2019 and 2018, respectively. The Williston Basin volumes were 6.8 MBbls per
day compared to 4.2 MBbls per day for 2019 and 2018, respectively. The following
table reflects NGL production prices, the price impact of our derivative
settlements and volumes for 2019 and 2018.
Years ended December 31,
2019 2018
NGL sales (per barrel) $ 12.17 $ 21.97 Impact of net cash paid related to settlement of derivatives (per barrel)(a)
- (1.98)
NGL net price including all derivative settlements (per barrel) $
12.17 $ 19.99
NGL production sales volumes (Mbbls) 10,043 6,733
Per day NGL production sales volumes (Mbbls/d) 27.5 18.4
__________
(a) Included in net gain (loss) on derivatives on the Consolidated Statements of Operations. •$234 million unfavorable change in net gain (loss) on derivatives primarily reflects changes in crude oil derivatives that were a result of increases in 2019 of forward commodity prices relative to our hedge positions. Settlements to be received on derivatives totaled$12 million for 2019 and settlements to be paid totaled$237 million for 2018. •$10 million decrease in commodity management revenues primarily due to lower crude sales volumes and lower prices on crude and natural gas sales. These decreases are offset by higher natural gas sales volumes in 2019 as a result of additional excess capacity in theDelaware Basin , which we utilized to purchase natural gas at depressedDelaware Basin pricing and transport to sales points outside the Basin. Related commodity management costs and expenses decreased$19 million and are discussed below. Cost and operating expense and operating income analysis: Years ended December 31, Favorable Per Boe Expense Favorable (Unfavorable) % 2019 2018 (Unfavorable) $ Change Change 2019 2018 (Millions) Costs and expenses: Depreciation, depletion and amortization$ 928 $ 777 $ (151) (19) %$15.23 $16.75 Lease and facility operating 374 272 (102) (38) %$6.13 $5.85 Gathering, processing and transportation 183 107 (76) (71) %$3.01 $2.30 Taxes other than income 178 157 (21) (13) %$2.92 $3.39 Exploration 95 75 (20) (27) % General and administrative: General and administrative expenses 172 150 (22) (15) %$2.83 $3.22 Equity-based compensation 34 32 (2) (6) %$0.57 $0.70 Total general and administrative 206 182 (24) (13) %$3.40 $3.92 Commodity management 163 182 19 10 % Net gain on sales of assets (Note 4) - (3) (3) (100) % Acquisition costs (Note 17) 3 - (3) NM Other-net 18 7 (11) (157) % Total costs and expenses$ 2,148 $ 1,756 $ (392) (22) % Operating income$ 144 $ 554 $ (410) (74) % __________ NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200. Significant components on our costs and expenses are comprised of the following: •$151 million increase in depreciation, depletion and amortization is primarily due to higher production volumes partially offset by a$1.52 decrease in the per Boe rate compared to 2018 primarily due to favorable technical revisions 51 -------------------------------------------------------------------------------- in theWilliston Basin . The decrease in the per Boe rate was also a result of the addition of new wells with lower relative cost per Boe. •$102 million increase in lease and facility operating expenses primarily related to increased production volumes and higher water management costs for 2019 compared to 2018. •$76 million increase in gathering, processing and transportation is due to growth in production volumes and the impact of new or modified contracts in theDelaware and Williston Basins. •$21 million increase in taxes other than income related to increased product revenues, previously discussed. •$20 million increase in exploration expenses is primarily due to higher unproved leasehold amortization in 2019. •$24 million increase in general and administrative expenses for 2019 compared to 2018. General and administrative expenses in 2019 included$8 million for costs associated with a voluntary exit program we offered to employees. Also included in the increase is approximately$10 million higher employee incentive bonus compared to 2018. Our general and administrative expenses per BOE decreased to an average$3.40 for 2019 compared to$3.92 for 2018. Excluding the$8 million related to the voluntary exit program, our rate per Boe averaged$3.27 in 2019. •$19 million decrease in commodity management expenses is primarily due to lower crude purchase volumes and depressedDelaware Basin pricing on physical natural gas cost of sales. These decreases are partially offset by higher natural gas sales volumes as discussed above. •$11 million increase in other expense for 2019 compared to 2018 primarily related to an$11 million charge in 2019 associated with an offer made by us to settle certain contractual disputes in theWilliston Basin (See Note 4 of Notes to Consolidated Financial Statements for details of this expense). Results below operating income Years ended December 31, Favorable Favorable (Unfavorable) (Unfavorable) % 2019 2018 $ Change Change (Millions) Operating income$ 144 $ 554 $ (410) (74) % Interest expense (159) (163) 4 2 % Loss on extinguishment of debt (47) (71) 24 34 % Gains on equity method investments transactions 380 - 380 NM Equity earnings (loss) 9 (6) 15 NM Other income 1 2 (1) (50) % Income from continuing operations before income taxes 328 316 12 4 % Provision for income taxes 70 74 4 5 % Income from continuing operations 258 242 16 7 % Loss from discontinued operations (2) (91) 89 98 % Net income$ 256 $ 151 $ 105 70 % __________ NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200. Interest expense decreased in 2019 compared to 2018 due to a lower amount of average debt outstanding in 2019 and lower average interest rates. Offsetting these decreases was approximately$3 million of fees for a bridge facility related to the Felix Acquisition. In the third quarter of 2019, we issued$600 million of Senior Notes due in 2027. The net proceeds from this offering were used to fund the purchase of$550 million aggregate principal amount of our 2022 Notes and 2023 Notes. As a result of the early retirement of these Senior Notes, we recorded a loss on extinguishment of debt of$47 million in 2019. In the second quarter of 2018, we used proceeds from the San Juan Gallup disposition and proceeds from the issuance of$500 million of Senior Notes due in 2026 to retire$921 million aggregate principal amount of our Senior Notes. As a result of the early retirement of these Senior Notes, we recorded a loss on extinguishment of debt of$71 million in 2018. See Note 8 of Notes to Consolidated Financial Statements for additional information regarding these transactions. Gains on equity method investments transactions in 2019 related to the sale of our 20 percent equity interest in the Whitewater natural gas pipeline and a distribution received related to our 25 percent equity interest in the Oryx pipeline. See Note 5 of Notes to Consolidated Financial Statements for details of these transactions. Loss from discontinued operations in 2018 primarily relates to a$147 million pretax loss on the sale of ourSan Juan 52 --------------------------------------------------------------------------------Gallup operations, which was sold in the first quarter of 2018. See Note 2 of Notes to Consolidated Financial Statements for detail of amounts included in discontinued operations. Management's Discussion and Analysis of Financial Condition and Liquidity Overview and Liquidity We expect our capital structure will provide us financial flexibility to meet our requirements for working capital and capital expenditures while maintaining a sufficient level of liquidity. Our primary sources of liquidity in 2020 are cash on hand, expected cash flows from operations, contributions from noncontrolling interests (see Note 14 of Notes to Consolidated Financial Statements), and, if necessary, borrowings on our credit facility. We anticipate that the combination of these sources should be sufficient to allow us to pursue our business strategy and goals through at least 2020. These goals include implementing a meaningful dividend, targeting a 7 percent to 10 percent free cash flow yield, driving down our leverage metrics from current levels and continuing to opportunistically repurchase our shares. Additional sources of liquidity, if needed and if available, include proceeds from asset sales, bank financings and proceeds from the issuance of long-term debt and equity securities. We note the following assumptions for 2020: •our planned capital expenditures, excluding acquisitions, are estimated to be approximately$1.675 billion to$1.8 billion of which$1.625 billion to$1.725 billion relates to drilling and completions, including facilities; and •we have hedged a portion of our anticipated 2020 oil and gas production as disclosed in Commodity Price Risk Management following this section. Potential risks associated with our planned levels of liquidity and the planned capital expenditures discussed above include: •lower than expected levels of cash flow from operations, primarily resulting from lower energy commodity prices or inflation on operating costs; •our ability to successfully integrate Felix's operation or to realize costs savings, revenues or other anticipated benefits of the Felix Acquisition; •significantly lower than expected capital expenditures could result in the loss of undeveloped leasehold; •reduced access to our credit facility pursuant to our financial covenants; and •higher than expected development costs, including the impact of inflation. Credit Facility Our Credit Facility (as defined in Note 8 of Notes to Consolidated Financial Statements), includes total commitments of$1.5 billion , on a$2.1 billion Borrowing Base with a maturity date ofApril 17, 2023 . Based on our current credit ratings, a Collateral Trigger Period applies that makes the Credit Facility subject to certain financial covenants and a Borrowing Base. The Credit Facility may be used for working capital, acquisitions, capital expenditures and other general corporate purposes. The financial covenants in the Credit Facility may limit our ability to borrow money, depending on the applicable financial metrics at any given time. For additional information regarding the terms of our Credit Facility see Note 8 of Notes to Consolidated Financial Statements. As ofDecember 31, 2019 , WPX had no borrowings outstanding and$28 million of letters of credit issued under the Credit Facility. Additionally, WPX was in compliance with our covenants under the Credit Facility as ofDecember 31, 2019 . Our unused borrowing availability was$1,472 million as ofDecember 31, 2019 . Strategic Partnerships In September andOctober 2019 , we entered into strategic relationships with two third-parties through two newly-formed subsidiaries for purposes of acquiring mineral interests and funding participation in future non-operated well interests. In accordance with and subject to the terms of the agreements, both parties have committed to fund future contributions, subject to certain limits, through the end of 2020 and 2022, respectively. The third-party contributions would represent 80 percent to 85 percent of the total contributions to the partnerships. WPX will be entitled to receive varying percentages of returns based upon achievement of certain predetermined thresholds. Pending Felix Acquisition As previously discussed, we signed an agreement inDecember 2019 to purchaseFelix Investments Holdings II, LLC for$2.5 billion . The closing is expected in first-quarter 2020. The$900 million cash portion and transaction costs at closing will be funded by the proceeds from the senior notes discussed below and, if necessary, our Credit Facility. OnJanuary 10, 2020 , we completed our debt offering of$900 million aggregate principal amount of 4.50% senior unsecured notes due 2030. The proceeds were deposited into an escrow account upon the closing of the offering. Upon release 53 -------------------------------------------------------------------------------- from escrow, WPX intends to use the proceeds to finance a portion of the cash consideration of the Felix Acquisition and to pay certain fees and expenses (see Note 17 of Notes to Consolidated Financial Statements). Commodity Price Risk Management To manage the commodity price risk and volatility of owning producing oil and gas properties, we enter into derivative contracts for a portion of our future production (see Note 16 of Notes to Consolidated Financial Statements). We chose not to designate our derivative contracts associated with our future production as cash flow hedges for accounting purposes. We have the following contracts as of the date of this filing shown at weighted average volumes and basin-level weighted average prices: Crude Oil 2020 2021 Volume Weighted Average Volume Weighted Average (Bbls/d) Price ($/Bbl) (Bbls/d) Price ($/Bbl) Fixed Price Swaps-WTI(a) 65,129$ 57.07 - $ - Fixed Price Swaptions-WTI - $ - 20,000$ 57.02 Fixed Price Costless Collars-WTI 20,000$53.33 -$63.48 - $ - Basis Swaps- Midland/Cushing 7,486$ (1.31) - $ - Basis Swaps- Brent/WTI Spread 5,000 $ 8.36 1,000 $ 8.00 Basis Swaps- Nymex Calendar Monthly Avg Roll 8,361 $ 0.57 - $ - __________ (a) Fixed Price Swaps include hedges related to a new partnership created to fund non-operated interests. Natural Gas 2020 2021 Volume Weighted Average Volume Weighted Average (BBtu/d) Price ($/MMBtu) (BBtu/d) Price ($/MMBtu) Basis Swaps-Waha 60$ (0.79) 70$ (0.59) 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 ofFebruary 26, 2020 were as follows: Standard and Poor's: Corporate Credit Rating BB- Senior Unsecured Debt Rating BB- Outlook Watch Positive Moody's Investors Service: LT Corporate Family Rating Ba3 Senior Unsecured Debt Rating B1 Outlook Review For Upgrade Fitch Ratings: LT Corporate Family Rating BB Senior Unsecured Debt Rating BB Outlook Positive Watch
At the time of the Felix Acquisition announcement or shortly thereafter, all three credit rating agencies indicated that WPX could receive credit rating upgrades following the closing of the Felix Acquisition.
54
--------------------------------------------------------------------------------
Sources (Uses) of Cash
Years Ended December 31,
2019 2018 2017
(Millions)
Net cash provided by (used in):
Operating activities $ 1,257 $ 883 $ 507
Investing activities (773) (896) (1,436)
Financing activities (422) (170) 624
Increase (decrease) in cash and cash equivalents and
restricted cash $ 62 $ (183) $ (305)
Operating activities
Net cash provided by operating activities increased in 2019 from 2018 primarily
due to higher production volumes in 2019 and realizations on our derivatives,
partially offset by higher operating costs and lower commodity prices.
Additionally, 2019 includes the receipt of approximately $38 million related to
an alternative minimum tax credit refund (see Note 9 of Notes to Consolidated
Financial Statements).
Net cash provided by operating activities increased in 2018 from 2017 primarily
due to higher production volumes and higher commodity prices in 2018, partially
offset by higher operating costs and an increase in settlements paid on our
derivatives.
Total cash provided by operating activities related to discontinued operations
excluding changes in working capital was approximately $44 million and $143
million for 2018 and 2017, respectively. Cash outflows related to previous
accruals for Powder River Basin gathering and transportation contracts retained
were $28 million , $47 million and $53 million for 2019, 2018 and 2017,
respectively.
Investing activities
The table below reflects capital expenditures, exclusive of partnerships, for
the periods presented.
Years Ended December 31,
2019 2018 2017
(Millions)
Incurred capital expenditures:
Drilling, completions and facilities $ 1,092 $ 1,327 $ 880
Land acquisitions 114 65 63
Infrastructure 91 81 102
Other 16 10 10
Discontinued operations, primarily drilling and
completions - 27 177
Total incurred capital expenditures 1,313 1,313 1,510 1,232
Changes in related accounts payable and accounts
receivable 44 (34) (71)
Cash capital expenditures reported on the Consolidated
Statement of
Cash Flows $ 1,357 $ 1,476 $ 1,161
Incurred capital expenditures related to partnerships was approximately $8
million in 2019.
Significant components related to proceeds from the sale of our assets are
comprised of the following:
2019
•$505 million of proceeds related to transactions involving our equity method
investments including our 20 percent equity interest in Whitewater natural gas
pipeline and our 25 percent equity interest in the Oryx pipeline (see Note 5 of
Notes to Consolidated Financial Statements); and
•$83 million in proceeds from the sale of certain non-core properties (see Note
4 of Notes to Consolidated Financial Statements).
2018
•$645 million of net proceeds from the sale of San Juan Gallup (see Note 2 of
Notes to Consolidated Financial Statements).
55
--------------------------------------------------------------------------------2017
•$155 million related to the sale of our natural gas-producing properties in theSan Juan Basin (see Note 2 of Notes to Consolidated Financial Statements). Net cash used in investing activities for 2018 includes$102 million of additional investment in equity method investments. Net cash used in investing activities for the year endedDecember 31, 2017 includes$798 million related to the acquisition of acreage in theDelaware Basin . Investing activities in 2017 includes net proceeds of$338 million from the formation of the joint venture with Howard (see Note 5 of Notes to Consolidated Financial Statements). Financing activities The following are significant financing activities by year: 2019 •$594 million of payments for retirement of long-term debt, including approximately$44 million of premium, offset by$593 million net proceeds from a debt issuance in the third quarter of 2019. See Note 8 of Notes to Consolidated Financial Statements for further discussion of our debt tender offers and debt issuance; •$330 million of net repayments on the Credit Facility; and •$58 million of payments for repurchases of common stock under a share repurchase program approved by the Board of Directors in third-quarter 2019 (see Note 14 of Notes to Consolidated Financial Statements). 2018 •$986 million of payments for retirement of long-term debt, including approximately$63 million of premium, partially offset by$494 million net proceeds from a debt issuance in the second quarter of 2018. See Note 8 of Notes to Consolidated Financial Statements for further discussion of our debt tender offers and debt issuance; •$330 million net borrowings on the Credit Facility; and •$11 million of preferred stock dividends. 2017 •InJanuary 2017 , we completed an equity offering of 51.675 million shares for net proceeds of approximately$670 million in conjunction with the acquisition of acreage in theDelaware Basin ; •$15 million of preferred stock dividends; and •payment of$165 million , including premium, to repurchase some of our 2020 Senior Notes partially offset by$148 million of net proceeds related to the issuance of additional notes due 2024. Off-Balance Sheet Financing Arrangements We had no guarantees of off-balance sheet debt to third parties or any other off-balance sheet arrangements atDecember 31, 2019 andDecember 31, 2018 . Although not a financing arrangement, we have provided a guarantee for certain obligations transferred as part of a 2018 divestment (see Note 2 of Notes to Consolidated Financial Statements). 56 -------------------------------------------------------------------------------- Contractual Obligations The table below summarizes the maturity dates of our contractual obligations atDecember 31, 2019 . 2020 2021 - 2022 2023 - 2024 Thereafter Total (Millions) Long-term debt, including current portion: Principal $ - $
73
132 262 222 138 754
Operating leases and associated service
commitments:
Drilling rig commitments(a) 73 23 1 - 97
Other 26 16 - - 42
Transportation commitments(b) 114 181 151 315 761
Oil and gas activities(c)(d) 107 99 77 38 321
Financial derivatives(e) 82 - - - 82
Other 14 14 3 1 32
Total obligations $ 548 $ 668 $ 1,510 $ 1,592 $ 4,318
__________
(a) Includes materials and services obligations associated with our drilling rig
contracts.
(b) Includes firm demand obligations of $22 million of which $21 million is
recorded as a liability as of December 31, 2019 . A liability was recorded in
2015 in conjunction with our exit from the Powder River Basin (see Note 2 of
Notes to Consolidated Financial Statements). Excludes additional commitments
totaling $875 million associated with projects for which a counterparty has not
completed construction.
(c) Includes gathering, processing and other oil and gas related services
commitments of $17 million of which $15 million is recorded as a liability as of
December 31, 2019 . Liabilities were recorded in 2015 in conjunction with our
exit from the Powder River Basin and associated with an abandoned area in the
Appalachian Basin .
(d) Excluded are liabilities associated with asset retirement obligations
totaling $97 million as of December 31, 2019 . The ultimate settlement and timing
of asset retirement obligations cannot be precisely determined in advance;
however, we estimate that approximately 21 percent of this liability will be
settled in the next five years.
(e) Obligations for financial derivatives are based on market information as of
December 31, 2019 , and assume contracts remain outstanding for their full
contractual duration. Because market information changes daily and is subject to
volatility, significant changes to the values in this category may occur.
Effects of Inflation
Although the impact of inflation has been insignificant in recent years, it is
still a factor in the United States economy. Operating costs are influenced by
both competition for specialized services and specific price changes in oil,
natural gas, NGLs and other commodities. We tend to experience inflationary
pressure on the cost of services and equipment when higher oil and gas prices
cause an increase in drilling activity in our areas of operation. Likewise,
lower prices and reduced drilling activity may lower the costs of services and
equipment.
Environmental
Our operations are subject to governmental laws and regulations relating to the
protection of the environment, and increasingly strict laws, regulations and
enforcement policies, as well as future additional environmental requirements,
could materially increase our costs of operation, compliance and any remediation
that may become necessary. In view of (1) trends in public and political
sentiment regarding environmental expectations; (2) a desire to continually
improve our environmental performance; and (3) elevating attention on emerging
public policy, our board added responsibilities to our Nominating and Governance
Committee and changed the name to the Nominating, Governance, Environmental &
Public Policy Committee . This is a recognition of the reality that new standards
and requirements will emerge for producers of traditional energy. The
Committee's amended charter provides for (1) overseeing management's monitoring
and enforcement of WPX's policies to protect the environment, including those
related to flaring and emissions; (2) monitoring emerging political, social and
environmental trends and major global legislative and regulatory developments
that may affect or require adjustments in our business operations; and (3)
advising the Board of Directors on significant stakeholder concerns and
shareholder proposals relating to environmental, public policy or
sustainability-related matters.
57
--------------------------------------------------------------------------------
Critical Accounting Estimates
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates, judgments and
assumptions that affect the reported amounts of assets, liabilities, revenues,
and expenses and the disclosure of contingent assets and liabilities. We believe
that the nature of these estimates and assumptions is material due to the
subjectivity and judgment necessary, the susceptibility of such matters to
change, and the impact of these on our financial condition or results of
operations.
In our management's opinion, the more significant reporting areas impacted by
management's judgments and estimates are as follows:
Successful Efforts Method of Accounting for Oil and Gas Exploration and
Production Activities
We use the successful efforts method of accounting for our oil- and
gas-producing activities. Estimated oil and natural gas reserves and estimated
market prices for oil and gas are a significant part of our financial
calculations. Following are examples of how these estimates affect financial
results:
•an increase (decrease) in estimated proved oil, natural gas and NGL reserves
can reduce (increase) our unit-of-production depreciation, depletion and
amortization rates; and
•changes in oil, natural gas, and NGL reserves and estimated market prices both
impact projected future cash flows from our properties. This, in turn, can
impact our periodic impairment analyses.
The process of estimating oil and natural gas reserves is very complex,
requiring significant judgment in the evaluation of all available geological,
geophysical, engineering and economic data. After being estimated internally,
approximately 100 percent of our reserves estimates are audited by independent
experts. The data may change substantially over time as a result of numerous
factors, including the historical 12 month weighted average price, additional
development cost and activity, evolving production history and a continual
reassessment of the viability of production under changing economic conditions.
As a result, material revisions to existing reserves estimates could occur from
time to time. Such changes could trigger an impairment of our oil and gas
properties and have an impact on our depreciation, depletion and amortization
expense prospectively. For example, a change of approximately 10 percent in our
total oil and gas reserves could change our annual depreciation, depletion and
amortization expense between approximately $83 million and $101 million . The
actual impact would depend on the specific basins impacted and whether the
change resulted from proved developed, proved undeveloped or a combination of
these reserves categories.
Estimates of future commodity prices, which are utilized in our impairment
analyses, consider market information including published forward oil and
natural gas prices. The forecasted price information used in our impairment
analyses is consistent with that generally used in evaluating our drilling
decisions and acquisition plans. Prices for future periods impact the production
economics underlying oil and gas reserve estimates. In addition, changes in the
price of oil and natural gas also impact certain costs associated with our
underlying production and future capital costs. The prices of oil and natural
gas are volatile and change from period to period, thus impacting our estimates.
Significant unfavorable changes in the estimated future commodity prices could
result in an impairment of our oil and gas properties. See impairments of
long-lived assets below.
We record the cost of leasehold acquisitions as incurred. Individually
significant lease acquisition costs are assessed annually, or as conditions
warrant, for impairment considering our future drilling plans, the remaining
lease term and recent drilling results. Lease acquisition costs that are not
individually significant are aggregated by prospect or geographically, and the
portion of such costs estimated to be nonproductive prior to lease expiration is
amortized over the average holding period. Changes in our assumptions regarding
the estimates of the nonproductive portion of these leasehold acquisitions could
result in impairment of these costs. Upon determination that specific acreage
will not be developed, the costs associated with that acreage would be impaired.
Additionally, our leasehold costs are evaluated for impairment if the proved
property costs in the basin are impaired. Our capitalized lease acquisition
costs totaled $1.6 billion at December 31, 2019 and are primarily associated
with our Delaware Basin acreage.
Impairments of Long-Lived Assets
We evaluate our long-lived assets for impairment when we believe events or
changes in circumstances indicate that we may not be able to recover the
carrying value. When an indicator of impairment has occurred, we compare our
estimate of undiscounted cash flows attributable to the assets to the carrying
value of the assets to determine if an impairment has occurred. If an impairment
has occurred, we determine the amount of impairment by estimating the fair value
of the assets. Our computations utilize judgments and assumptions that include
estimates of the undiscounted future cash flows, discounted future cash flows,
estimated fair value of the asset, and the current and future economic
environment in which the asset is operated.
We assess our proved properties for impairment using estimates of future
undiscounted cash flows. Significant judgments and assumptions are inherent in
these assessments and include estimates of reserves quantities, estimates of
future commodity prices (developed in consideration of market information,
internal forecasts and published forward prices adjusted for locational
58
--------------------------------------------------------------------------------
basis differentials), drilling plans, expected capital and lease operating
costs. The assessment performed as of December 31, 2019 did not identify any
properties with a carrying value in excess of those estimated undiscounted cash
flows. Therefore, no impairment charges were recorded in 2019 based on this
assessment.
The assessments described above included approximately $5.9 billion of net book
value associated with our proved properties. Many judgments and assumptions are
inherent and to some extent interdependent of one another in our estimate of
future cash flows used to evaluate these assets. The use of alternate judgments
and assumptions could result in the recognition of different levels of
impairment charges in the consolidated financial statements. As previously noted
within "Successful Efforts Method of Accounting for Oil and Gas Exploration and
Production Activities", estimated natural gas and oil reserves and estimated
future commodity prices for oil and gas are a significant part of our impairment
analysis. Commodity prices are significantly volatile and prices for a barrel of
oil ranged from over $100 per barrel to less than $30 per barrel since 2014. Our
forecasted price assumptions reflect a long-term view of pricing but also
consider current prices and are consistent with pricing assumptions generally
used in evaluating our drilling decisions and acquisition plans. Approximately
56 percent of our future production considered in the impairment assessment is
in years 2025 and beyond. If the estimated commodity revenues (only one of the
many estimates involved) of the predominately oil proved properties were lower
by 15 to 25 percent, these properties could be at risk for impairment. Because
of the uncertainty inherent in these factors, we cannot predict when or if
future impairment charges will be recorded. If impairments were required, the
charges could be significant.
Valuation of Deferred Tax Assets and Liabilities
We record deferred taxes for the differences between the tax and book basis of
our assets and liabilities as well as loss or credit carryovers to future years.
Included in our deferred taxes are deferred tax assets primarily resulting from
certain federal and state tax loss carryovers generated in the current and prior
years and alternative minimum tax credits. We must periodically evaluate whether
it is more likely than not we will realize these deferred tax assets and
establish a valuation allowance for those that do not meet the more likely than
not threshold. When assessing the need for a valuation allowance, we primarily
consider future reversals of existing taxable temporary differences. To a lesser
extent, we may also consider future taxable income exclusive of reversing
temporary differences and carryovers, and tax-planning strategies that would, if
necessary, be implemented to accelerate taxable amounts to utilize expiring
carryovers. The ultimate amount of deferred tax assets realized could be
materially different from those recorded, as influenced by future operational
performance, potential changes in jurisdictional income tax laws and other
circumstances surrounding the actual realization of related tax assets.
As of December 31, 2019 , our assessment of federal net operating loss carryovers
was that no valuation allowance was required; however, a future pretax loss or
limitation due to an ownership change may result in the need for a valuation
allowance on our deferred tax assets.
The determination of our state deferred tax liability requires judgment as our
state deferred tax rates can change periodically based on changes in our
operations. Our state deferred tax rates are based upon our current entity
structure, the jurisdictions in which we operate and corresponding statutory tax
rates.
Fair Value Measurements
A small portion of our energy derivative assets and liabilities trade in markets
with limited availability of pricing information requiring us to use
unobservable inputs and are considered Level 3 in the fair value hierarchy. For
Level 2 transactions, we do not make significant adjustments to observable
prices in measuring fair value as we do not generally trade in inactive markets.
The determination of fair value for our energy derivative assets and liabilities
also incorporates the time value of money and various credit risk factors, which
can include the credit standing of the counterparties involved, master netting
arrangements, the impact of credit enhancements (such as cash collateral posted
and letters of credit) and our nonperformance risk on our energy derivative
liabilities. The determination of the fair value of our energy derivative
liabilities does not consider noncash collateral credit enhancements. For net
derivative assets, we apply a credit spread, based on the credit rating of the
counterparty, against the net derivative asset with that counterparty. For net
derivative liabilities, we apply our own credit rating. We derive the credit
spreads by using the corporate industrial credit curves for each rating category
and building a curve based on certain points in time for each rating category.
The spread comes from the discount factor of the individual corporate curves
versus the discount factor of the LIBOR curve. At December 31, 2019 , the credit
reserve is less than $1 million on our net derivative assets and net derivative
liabilities. Considering these factors and that we do not have significant risk
from our net credit exposure to derivative counterparties, the impact of credit
risk is not significant to the overall fair value of our derivatives portfolio.
Of the $24 million net derivative liability at December 31, 2019 , $34 million of
liability expires in the next 12 months. Our derivatives portfolio is largely
comprised of exchange-traded products or like products where price transparency
has not historically been a concern. Due to the nature of the markets in which
we transact and the relatively short tenure of our
59--------------------------------------------------------------------------------
derivatives portfolio, we do not believe it is necessary to make an adjustment for illiquidity. We regularly analyze the liquidity of the markets based on the prevalence of broker pricing and exchange pricing for products in our derivatives portfolio. There were no instruments included in Level 3 atDecember 31, 2019 . For the year endedDecember 31, 2017 , we recognized an impairment in discontinued operations on natural gas-producing properties held for sale in theSan Juan Basin as a result of comparing our book value to the estimated fair value, less costs to sell, based on the probability-weighted cash flows of expected sales proceeds. In conjunction with exchanges of leasehold, we estimated the fair value of the leasehold through discounted cash flow models and consideration of market data. See Note 15 of Notes to Consolidated Financial Statements. Contingent Liabilities We record liabilities for estimated loss contingencies, including royalty litigation, environmental and other contingent matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. Liabilities for contingent losses are based upon our assumptions and estimates and upon advice of legal counsel, engineers or other third parties regarding the probable outcomes of the matter. As new developments occur or more information becomes available, our assumptions and estimates of these liabilities may change. Changes in our assumptions and estimates or outcomes different from our current assumptions and estimates could materially affect future results of operations for any particular quarterly or annual period. See Note 10 of Notes to Consolidated Financial Statements.
© Edgar Online, source
