The Company files income tax returns in the U.S. federal jurisdiction and various state and foreign jurisdictions. The Internal Revenue Service has closed examinations of the 2012 and prior tax years and, with few exceptions, the Company believes that it is no longer subject to examinations by state and foreign tax authorities for years before 2011. As of SeptemberJune 30, 2017,2023, there are no proposed adjustments had been proposed in any jurisdiction that would have a significant effect on the Company's liquidity, future results of operations or financial position.
Averageaforementioned decrease in oil NGL and gas prices increased duringrevenues.
•During the three months ended SeptemberJune 30, 2017 to $45.352023, the Company declared a base and variable dividend of $1.25 per Bbl, $18.96share and $2.09 per Bblshare, respectively, and $2.58 per Mcf, respectively,paid dividends of $781 million, as compared to $41.44a declared base and variable dividend of $0.78 per Bbl, $12.46share and $6.60 per Bblshare, respectively, and $2.43 per Mcf, respectively, fordividend payments of $1.8 billion during the same period in 2016.2022.
PIONEER NATURAL RESOURCES COMPANY
Net cash provided by operating activities increased to $455 million for•During the three months ended SeptemberJune 30, 2017,2023, the Company repurchased 601 thousand shares for $124 million under the Company's stock repurchase program, as compared to $441repurchases of 2.1 million shares for $499 million during the same period in 2016. The $14 million increase in net cash provided by operating activities for the three months ended September 30, 2017, as compared to the same period in 2016, is primarily due to increases in the Company's oil and gas revenues as a result of increases in commodity prices and sales volumes, partially offset by a $156 million reduction in cash provided by commodity derivatives.
2022.•As of SeptemberJune 30, 2017,2023 and December 31, 2022, the Company's net debt to book capitalization was five19 percent as compared to twoand 15 percent, at December 31, 2016.respectively.
FourthThird Quarter 20172023 Outlook
Based on current estimates, the Company expects the following operating and financial results for the third quarter ending December 31, 2017:of 2023:
Production is forecasted to average 292,000 to 302,000 BOEPD.
Production costs (including production and ad valorem taxes and transportation costs) are expected to average $7.50 to $9.50 | | | | | |
| Three Months Ending September 30, 2023 |
| Guidance |
| ($ in millions, except per BOE amounts) |
Average daily production (MBOE) | 705 - 725 |
Average daily oil production (MBbls) | 367 - 377 |
Production costs per BOE | $10.50 - $12.00 |
DD&A per BOE | $10.50 - $12.00 |
Exploration and abandonments expense | $10 - $20 |
General and administrative expense | $80 - $90 |
| |
Interest expense | $40 - $45 |
Other expense | $20 - $40 |
Cash flow impact from firm transportation (a) | $(60) - $(20) |
Current income tax provision | $175 - $250 |
Effective tax rate | 22% - 27% |
_____________________
(a)The expected cash flow impact from firm transportation is primarily based on current NYMEX strip commodity prices. DD&A expense is expected(i) the forecasted differential between Midland WTI oil prices and Brent oil prices less the costs to average $13.50transport purchased oil from the areas of the Company's production to $15.50 per BOE.
Total exploration and abandonment expense is expected to be $20 million to $30 million. General and administrative expense is expected to be $80 million to $85 million. Interest expense is expected to be $34 million to $39 million, and other expense is expected to be $60 million to $70 million. Other expense is expected to include (i) $45 million to $55 million of charges associated
PIONEER NATURAL RESOURCES COMPANY
with excess firm gathering and transportation commitmentsthe Gulf Coast and (ii) other miscellaneous charges. Accretionoil price fluctuations between the time the Company purchases the oil from its areas of discount on asset retirement obligationsoperation and when the oil is expecteddelivered and sold to be $4 millionGulf Coast refineries or exported to $7 million.international markets. To the extent that the Company's Gulf Coast sales of purchased oil does not cover the purchase price and associated firm transport costs, the Company's results of operations will reflect the negative cash flow impact attributable to the shortfall.
The Company's effective income tax rate is expected to range from 35 percent to 40 percent. Current income taxes are expected to be less than $5 million.
Operations and Drilling Highlights
The following table summarizesAs of June 30, 2023, the Company's average daily oil, NGL, gasdrilling and total production by asset area during the nine months ended September 30, 2017:
|
| | | | | | | | | | | | |
| | Oil (Bbls) | | NGLs (Bbls) | | Gas (Mcf) | | Total (BOE) |
Permian Basin | | 141,428 |
| | 42,168 |
| | 188,587 |
| | 215,027 |
|
South Texas - Eagle Ford Shale | | 7,033 |
| | 6,758 |
| | 41,776 |
| | 20,753 |
|
Raton Basin | | — |
| | — |
| | 89,220 |
| | 14,870 |
|
West Panhandle | | 1,743 |
| | 3,391 |
| | 6,197 |
| | 6,167 |
|
South Texas - Other | | 1,230 |
| | 201 |
| | 18,370 |
| | 4,493 |
|
Other | | 4 |
| | 1 |
| | 56 |
| | 15 |
|
Total | | 151,438 |
| | 52,519 |
| | 344,206 |
| | 261,325 |
|
The Company's liquids production increased to 78 percent of total production on a BOE basis for the nine months ended September 30, 2017, as compared to 75 percent for the same period last year.
The following table summarizes by geographic area the Company's findingcompletions program included operating 22 drilling rigs and development costs incurred during the nine months ended September 30, 2017:
|
| | | | | | | | | | | | | | | | | | | | |
| | Acquisition Costs | | Exploration Costs | | Development Costs | | Total |
| | Proved | | Unproved | | | |
| | (in millions) |
Permian Basin | | $ | 7 |
| | $ | 125 |
| | $ | 1,349 |
| | $ | 403 |
| | $ | 1,884 |
|
South Texas - Eagle Ford Shale | | — |
| | — |
| | 67 |
| | 26 |
| | 93 |
|
Raton Basin | | — |
| | — |
| | — |
| | 2 |
| | 2 |
|
West Panhandle | | — |
| | — |
| | 1 |
| | 6 |
| | 7 |
|
South Texas - Other | | — |
| | — |
| | — |
| | 5 |
| | 5 |
|
Other | | — |
| | — |
| | 4 |
| | — |
| | 4 |
|
Total | | $ | 7 |
| | $ | 125 |
| | $ | 1,421 |
| | $ | 442 |
| | $ | 1,995 |
|
The following table summarizes the Company's development and exploration/extension drilling activities for the nine months ended September 30, 2017:
|
| | | | | | | | | | | | |
| | Development Drilling |
| | Beginning Wells in Progress | | Wells Spud | | Successful Wells | | Ending Wells in Progress |
Permian Basin | | 8 |
| | 15 |
| | 6 |
| | 17 |
|
South Texas - Eagle Ford Shale | | 4 |
| | 1 |
| | 5 |
| | — |
|
South Texas - Other | | — |
| | 2 |
| | — |
| | 2 |
|
Total | | 12 |
| | 18 |
| | 11 |
| | 19 |
|
|
| | | | | | | | | | | | | | | |
| | Exploration/Extension Drilling |
| | Beginning Wells in Progress | | Wells Spud | | Successful Wells | | Unsuccessful Wells | | Ending Wells in Progress |
Permian Basin | | 119 |
| | 163 |
| | 150 |
| | 1 |
| | 131 |
|
South Texas - Eagle Ford Shale | | 14 |
| | 10 |
| | 6 |
| | 1 |
| | 17 |
|
Total | | 133 |
| | 173 |
| | 156 |
| | 2 |
| | 148 |
|
PIONEER NATURAL RESOURCES COMPANY
Permian Basin area. During 2017, the Company expected to place approximately 260 horizontal wells on production, weighted heavily to the second half of the year. However, due to unforeseen drilling delays during the first half of the year, the Company revised this forecast during the second quarter of 2017 and now expects to place approximately 230 horizontal wells on production (190 horizontal wellssix frac fleets in the northern portionMidland Basin. The Company will continue to evaluate its drilling and completions program with future activity levels assessed regularly.
Pioneer is the largest acreage holder in the Spraberry/Wolfcamp field in the Midland Basin of the play and 40 horizontal wells inWest Texas. In the southern portion of the play).Spraberry/Wolfcamp field, the Company has a joint venture ("JV") with Sinochem Petroleum USA LLC, a U.S. subsidiary of the Sinochem Group. During 2017, approximately 55the six months ended June 30, 2023, the Company successfully completed 226 horizontal wells in the non-JV portion of the Midland Basin and 26 horizontal wells in the JV portion of the Midland Basin. In the non-JV portion of the Midland Basin, 40 percent of the horizontal wells are planned to be drilled in the Wolfcamp B interval, 30 percent in the Wolfcamp A interval and 15 percent in the Lower Spraberry Shale interval. During the first nine months of 2017, the Company successfully completed 137 horizontal wells in the northern portion of the play and 19 horizontal wells in the southern portion of the play. In the northern portion of the play, approximately 45 percent of wells placed on production were Spraberry interval wells, 31 percent were Wolfcamp B interval wells, approximately 4027 percent were Wolfcamp A interval wells and the remaining 15two percent were Lower Spraberry ShaleWolfcamp D interval wells. The majorityIn the southern JV portion of the Midland Basin, all of the wells placed on production in the southern portion of the play were Wolfcamp A or B interval wells.
The Company continues to utilize its integrated services to control well costsDevelopment and operating costs in addition to supporting the execution of itsexploration/extension drilling and production activities in the Spraberry/Wolfcamp field. During the three months ended September 30, 2017, the Company utilized up to seven of its eight Company-owned fracture stimulation fleets to support its drilling operations in the Spraberry/Wolfcamp field. The Company also owns other field service equipment that supports its drilling and production operations, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, blowout preventers, construction equipment and fishing tools. In addition, Pioneer Sands LLC (the Company's wholly-owned sand mining subsidiary)activity is supplying high-quality brown sand for proppant, which is being used to fracture stimulate horizontal wells in the Spraberry and Wolfcamp Shale intervals.as follows:
The Company has been and continues to pursue initiatives to improve drilling and completion efficiencies and reduce costs. The Company's long-term growth plan also continues to focus on optimizing the development of the field and addressing the future requirements for water sourcing and disposal, field infrastructure, gas processing, sand, pipeline takeaway capacity for its products, oilfield services, tubulars, electricity, buildings, roads and labor.
The Company is constructing a field-wide water distribution system to reduce the cost of water for drilling and completion activities and to ensure that adequate supplies of water are available to support the Company's long-term growth plan for the Spraberry/Wolfcamp field. During 2017 the Company has expanded its mainline system, subsystems and frac ponds to efficiently deliver water to Pioneer's drilling locations. The Company signed an agreement with the city of Midland to upgrade the city's wastewater treatment plant in return for a dedicated long-term supply of water from the plant. The 2017 program includes $10 million of engineering capital to begin work on this upgrade. Pioneer expects to spend approximately $110 million over the 2017 through 2019 period for the Midland plant upgrade. In return, the Company will receive approximately two billion barrels of low-cost, non-potable water over a 28-year contract period (up to 240 thousand barrels per day) to support its completion operations.
The Company's sand mine in Brady, Texas, which is strategically located within close proximity (approximately 190 miles) of the Spraberry/Wolfcamp field, provides a secure sand source for the Company's horizontal drilling program. During 2017 the Company completed an optimization project of its existing sand mining facilities that improved yields and reduced the Company's overall cost of sand supplies.
Eagle Ford Shale area. During 2017, the Company operated two rigs in the Eagle Ford Shale area and drilled 11 new Eagle Ford wells. The objective of this drilling program was to test longer laterals with wider spacing and higher intensity completions in the new wells. The Company's 2017 completion plans included completing the 11 new Eagle Ford Shale wells and nine wells that were drilled but not completed in 2016. All nine of the wells that were drilled but not completed in 2016 and two of the 11 wells drilled in 2017 were placed on production during the nine months ended September 30, 2017. The remaining nine wells are expected to be placed on production during the three months ended December 31, 2017.
West Panhandle area. During the three months ended September 30, 2017, the Company experienced unplanned downtime due to a fire at a third-party gas processing plant, where liquids-rich gas from the Company's West Panhandle field is processed into gas and NGLs. As a result of the fire, West Panhandle field production was shut in. Repairs to the plant are underway, but it is expected to be several months before the plant can be placed back into service. As a result, the third party and Pioneer have made modifications to their respective facilities to enable field production to resume, with the gas volumes being rerouted to another gas processing facility operated by the third party. Production from the field resumed in late October.
| | | | | | | | | | | | | | | | | |
| Six Months Ended June 30, 2023 |
| Development | | Exploration/Extension | | Total |
Beginning wells in progress | 11 | | | 292 | | | 303 | |
Wells spud | 8 | | | 241 | | | 249 | |
| | | | | |
Successful wells | (10) | | | (242) | | | (252) | |
| | | | | |
Ending wells in progress | 9 | | | 291 | | | 300 | |
| | | | | |
| | | | | |
| | | | | |
PIONEER NATURAL RESOURCES COMPANY
Costs incurred are as follows:
| | | | | |
| Six Months Ended June 30, 2023 |
| ( in millions) |
Proved property acquisition costs (a) | $ | 173 | |
Unproved property acquisitions (a) | 82 | |
Exploration/extension costs | 2,046 | |
Development costs | 344 | |
Asset retirement obligations | (43) | |
| $ | 2,602 | |
_____________________
(a)Includes $148 million of noncash acquisition costs related to nonmonetary transactions in which the Company exchanged both proved and unproved oil and gas properties in the Midland Basin with unaffiliated third parties. See Note 3 of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information. Results of Operations
Oil and gas revenues. Oil and gas revenues totaled $855 million and $2.4 billion for the three and nine months ended September 30, 2017, respectively, as compared to $643 million and $1.7 billion for the same respective periods in 2016.
The increase inCompany's oil and gas revenues during the three months ended September 30, 2017, as compared to the same period in 2016, is primarily due to increasesare derived from sales of nine percent, 52 percent and six percent in oil, NGL and gas production. Increases or decreases in the Company's revenues, profitability and future production are highly dependent on commodity prices. Prices are market driven and future prices respectively, and increases of 20 percent, 16 percent and two percent in daily oil, NGL and gas sales volumes, respectively. The increase in oil and gas revenues during the nine months ended September 30, 2017, as compared to the same period in 2016, is primarilywill fluctuate due to increasessupply and demand factors, availability of 25 percent, 49 percenttransportation, seasonality, geopolitical developments and 36 percent in oil, NGL and gas prices, respectively, and increases of 16 percent and 21 percent in daily oil and NGL sales volumes, respectively.economic factors, among other items.
The following table provides average | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | | | Six Months Ended June 30, | | |
| 2023 | | 2022 | | Change | | 2023 | | 2022 | | Change |
| (in millions) |
Oil and gas revenues | $ | 2,977 | | | $ | 4,639 | | | $ | (1,662) | | | $ | 6,142 | | | $ | 8,570 | | | $ | (2,428) | |
Average daily sales volumes for the three and nine months ended September 30, 2017 and 2016:are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | | | Six Months Ended June 30, | | | | | |
| 2023 | | 2022 | | Change | | 2023 | | 2022 | | Change | | | |
Oil (Bbls) | 369,070 | | | 347,964 | | | 6 | % | | 365,214 | | | 351,597 | | | 4 | % | | | | | | |
NGLs (Bbls) | 181,098 | | | 160,183 | | | 13 | % | | 174,329 | | | 156,576 | | | 11 | % | | | | | | |
Gas (Mcf) | 963,064 | | | 808,181 | | | 19 | % | | 936,595 | | | 792,847 | | | 18 | % | | | | | | |
Total (BOE) | 710,678 | | | 642,844 | | | 11 | % | | 695,643 | | | 640,314 | | | 9 | % | | | | | | |
| | | | | | | | | | | | | | | | | |
Liquids percentage of total production | 77 | % | | 79 | % | | (2 | %) | | 78 | % | | 79 | % | | (1 | %) | | | | | | |
|
| | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
Oil (Bbls) | | 161,634 |
| | 134,240 |
| | 151,438 |
| | 130,602 |
|
NGLs (Bbls) | | 57,346 |
| | 49,235 |
| | 52,519 |
| | 43,252 |
|
Gas (Mcf) | | 340,384 |
| | 332,415 |
| | 344,206 |
| | 343,828 |
|
Total (BOEs) | | 275,711 |
| | 238,878 |
| | 261,325 |
| | 231,158 |
|
Average daily BOE sales volumes increased by 15 percent and 13 percent for the three and ninesix months ended SeptemberJune 30, 2017, respectively,2023, as compared to the same respective periods in 2016, principally2022, primarily due to the Company's successful Spraberry/Wolfcamp horizontal drilling program.
The oil, NGL and gas prices thatreported by the Company reports are based on the market prices received for each commodity. The following table provides the Company's averageCommodity prices for the three and ninesix months ended SeptemberJune 30, 20172023, as compared to the same periods in 2022, decreased due to the aforementioned volatility in worldwide oil, NGL and 2016:gas demand. The average prices are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | | | | Six Months Ended June 30, | | | | | |
| 2023 | | 2022 | | Change | | | 2023 | | 2022 | | Change | | | |
Oil price per Bbl | $ | 72.90 | | | $ | 110.56 | | | (34 | %) | | | $ | 74.00 | | | $ | 102.54 | | | (28 | %) | | | | | | |
NGL price per Bbl | $ | 22.43 | | | $ | 44.21 | | | (49 | %) | | | $ | 24.76 | | | $ | 42.83 | | | (42 | %) | | | | | | |
Gas price per Mcf | $ | 1.81 | | | $ | 6.72 | | | (73 | %) | | | $ | 2.77 | | | $ | 5.79 | | | (52 | %) | | | | | | |
Price per BOE | $ | 46.03 | | | $ | 79.31 | | | (42 | %) | | | $ | 48.78 | | | $ | 73.94 | | | (34 | %) | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
Oil (per Bbl) | | $ | 45.35 |
| | $ | 41.44 |
| | $ | 46.41 |
| | $ | 37.27 |
|
NGL (per Bbl) | | $ | 18.96 |
| | $ | 12.46 |
| | $ | 18.38 |
| | $ | 12.37 |
|
Gas (per Mcf) | | $ | 2.58 |
| | $ | 2.43 |
| | $ | 2.66 |
| | $ | 1.96 |
|
Total (per BOE) | | $ | 33.72 |
| | $ | 29.24 |
| | $ | 34.10 |
| | $ | 26.29 |
|
SalesNet effect from sales of purchased oil and gas. commodities. The Company periodically enters into pipeline capacity commitments in order to secure available oil, NGL and gas transportation capacity from the Company’sCompany's areas of production.production and to secure diesel supply from the Gulf Coast. The Company also enters into purchase commitments to secure sand supply for the Company's operations in the Midland Basin. The Company enters into purchase transactions with third parties and separate sale transactions with third parties to diversify a portion of the Company's WTI oil and gas sales to a(i) Gulf Coast market pricerefineries, (ii) Gulf Coast and West Coast gas
PIONEER NATURAL RESOURCES COMPANY
markets and (iii) international oil markets, and to satisfy unused gas pipeline capacity commitments. The Company periodically sells diesel and sand to unaffiliated third parties in the Permian Basin if it has supply in excess of its operational needs. Revenues and expenses from these transactions are generally presented on a gross basis in sales of purchased commodities and purchased commodities expense in the accompanying consolidated statements of operations as the Company acts as a principal in the transaction by assuming both the riskrisks and rewards of ownership, including credit risk, of the commodities purchased and the responsibility to deliver the commodities sold. In conjunction with the Company's downstream sales, the Company also enters into pipeline capacity and storage commitments in order to secure available oil and gas transportation capacity from the Company's areas of production to downstream sales points and storage capacity at downstream sales points. The transportation and storage costs associated with these transactions are included in purchased commodities expense.
The net effect of third party purchases andfrom sales of oil and gaspurchased commodities is as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | | | Six Months Ended June 30, | | | |
| 2023 | | 2022 | | Change | | 2023 | | 2022 | | Change | |
| (in millions) | |
Sales of purchased commodities | $ | 1,583 | | | $ | 2,366 | | | $ | (783) | | | $ | 3,014 | | | $ | 4,583 | | | $ | (1,569) | | |
Purchased commodities expense | 1,642 | | | 2,382 | | | (740) | | | 3,127 | | | 4,534 | | | (1,407) | | |
| $ | (59) | | | $ | (16) | | | $ | (43) | | | $ | (113) | | | $ | 49 | | | $ | (162) | | |
The change in the net effect from sales of purchased commodities for the three and ninesix months ended SeptemberJune 30, 2017 was a loss of $14 million and $47 million, respectively,2023, as compared to a loss of $14 million and $51 million for the same respective periods in 2016.2022, is primarily attributable to rising oil prices in 2022, which resulted in oil that was purchased and in transit via pipeline to the Gulf Coast or in Gulf Coast storage being sold in the following month at higher oil prices. In contrast, oil prices have been declining during 2023 resulting in marginal losses on oil sold from storage in the following month.
Firm transportation payments on excess pipeline capacity commitments are included in other expense in the accompanying consolidated statements of operations. See Note L13 of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information. Interest and other income (loss), net.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | | | | Six Months Ended June 30, | | | | |
| 2023 | | 2022 | | Change | | | 2023 | | 2022 | | Change | | |
| (in millions) | | |
Interest and other income (loss), net | $ | 43 | | | $ | (56) | | | $ | 99 | | | | $ | 7 | | | $ | 69 | | | $ | (62) | | | |
The change in net interest and other income (loss) for the three and six months ended June 30, 2023, as compared to the same periods in 2022, is primarily due to changes in the fair value of the Company's investment in affiliate resulting in a noncash gain of $18 million and a noncash loss of $35 million, during the three and six months ended June 30, 2023, respectively, as compared to a noncash loss of $65 million and a noncash gain of $32 million for the same periods in 2022, respectively.
See Note 4 of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information on transportation commitment charges.changes in fair value.
PIONEER NATURAL RESOURCES COMPANY
Derivative loss, net.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | | | | Six Months Ended June 30, | | | |
| 2023 | | 2022 | | Change | | | 2023 | | 2022 | | Change | |
| (in millions) | |
Commodity price derivatives: | | | | | | | | | | | | | |
Noncash derivative gain (loss), net | $ | — | | | $ | 72 | | | $ | (72) | | | | $ | — | | | $ | (39) | | | $ | 39 | | |
Cash payments on settled derivatives, net | — | | | (75) | | | 75 | | | | — | | | (131) | | | 131 | | |
Total commodity derivative loss, net | — | | | (3) | | | 3 | | | | — | | | (170) | | | 170 | | |
Marketing derivatives: | | | | | | | | | | | | | |
Noncash derivative gain (loss), net | 20 | | | (68) | | | 88 | | | | (16) | | | (24) | | | 8 | | |
Cash payments on settled derivatives | (16) | | | (17) | | | 1 | | | | (31) | | | (29) | | | (2) | | |
Total marketing derivative gain (loss), net | 4 | | | (85) | | | 89 | | | | (47) | | | (53) | | | 6 | | |
Conversion option derivatives: | | | | | | | | | | | | | |
Noncash derivative gain (loss), net | (2) | | | 23 | | | (25) | | | | (2) | | | 23 | | | (25) | | |
Cash receipts (payments) on settled derivatives, net | (3) | | | — | | | (3) | | | | 4 | | | — | | | 4 | | |
Total conversion option derivative gain (loss), net | (5) | | | 23 | | | (28) | | | | 2 | | | 23 | | | (21) | | |
Derivative loss, net | $ | (1) | | | $ | (65) | | | $ | 64 | | | | $ | (45) | | | $ | (200) | | | $ | 155 | | |
Commodity price derivatives. The Company primarily utilizes derivative contracts to reduce the effect of price volatility on the commodities the Company produces and other income. Interestsells. As of June 30, 2023, the Company has outstanding oil derivative contracts for three thousand Bbls per day of Brent/WTI basis swaps for January 2024 through December 2024. The basis swap contracts fix the basis differential between the WTI index price (the price at which the Company buys Midland Basin oil for transport to the Gulf Coast) and other incomethe Brent index price (the price at which a portion of the Midland Basin purchased oil is sold in the Gulf Coast market) at a weighted average differential of $4.33.
Marketing derivatives. The Company uses marketing derivatives to diversify its oil pricing to Gulf Coast and international markets.As of June 30, 2023, the Company's marketing derivatives reflect long-term marketing contracts whereby the Company agreed to purchase and simultaneously sell, at an oil terminal in Midland, Texas, (i) 50 thousand barrels of oil per day beginning January 1, 2021 and ending December 31, 2026, (ii) 40 thousand barrels of oil per day beginning May 1, 2022 and ending April 30, 2027 and (iii) 30 thousand barrels of oil per day beginning August 1, 2022 and ending July 31, 2027.
The price the Company pays to purchase the oil volumes under the purchase contract is based on a Midland WTI price and the price the Company receives for the threeoil volumes sold is the WASP that a non-affiliated counterparty receives for selling oil through a Gulf Coast storage and nine months ended September 30, 2017 was $17 million and $44 million, respectively, as compared to $7 million and $21 millionexport facility at prices that are highly correlated with Brent oil prices during the same month of the purchase. Based on the form of the long-term marketing contracts, the Company accounts for the same respective periods in 2016. The increase in interest and other incomecontracts as derivative instruments not designated as hedges.
Conversion option derivatives. Certain holders of the Company's Convertible Notes exercised their conversion options during the three and ninesix months ended SeptemberJune 30, 2017,2023 and 2022. Per the terms of the notes indenture, the Company elected to settle the conversions in cash at the end of the Settlement Period. The Company's election to settle an exercised conversion option in cash results in a forward contract during the Settlement Period that is accounted for as compareda derivative instrument not designated as a hedge. The Company's conversion option derivatives represent the change in the cash settlement obligation that occurs during the Settlement Period related to conversion options exercised by certain holders of the same respective periods in 2016, was primarily dueCompany's Convertible Notes.
The Company's open derivative contracts are subject to (i) increases of $4 millionmarket risk. See "Item 3. Quantitative and $11 million for the threeQualitative Disclosures About Market Risk" and nine months ended September 30, 2017, respectively, in interest income on short-termNote 4 and long-term investments and (ii) severance and sales tax refunds of $5 million and $13 million for the three and nine months ended September 30, 2017, respectively. See Note K5 of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information.
PIONEER NATURAL RESOURCES COMPANY
Gain (loss) on disposition of assets, net.
Derivative gains (losses), net. The Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts to (i) reduce the effect | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | | | | Six Months Ended June 30, | | | | | | |
| 2023 | | 2022 | | Change | | | 2023 | | 2022 | | Change | | | | |
| (in millions) | | | | |
Gain (loss) on disposition of assets, net | $ | (3) | | | $ | 36 | | | $ | (39) | | | | $ | 22 | | | $ | 70 | | | $ | (48) | | | | | |
Net gain (loss) on disposition of price volatility on the commodities the Company produces and sells or consumes, (ii) support the Company's annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. During the three and nine months ended September 30, 2017, the Company recorded $133 million of net derivative losses and $153 million of net derivative gains, respectively, on commodity price, diesel price and interest rate derivatives, of which $28 million and $62 million, respectively, represented net cash receipts. During the three and nine months ended September 30, 2016, the Company recorded $91 million of net derivative gains and $95 million of net derivative losses, respectively, on commodity price, diesel price and interest rate derivatives, of which $184 million and $533 million, respectively, represented net cash receipts.
The following tables detail the net cash receipts (payments) on the Company's commodity derivatives and the relative price impact (per Bbl or Mcf)assets for the three and ninesix months ended SeptemberJune 30, 20172023 primarily represents nonmonetary transactions in which the Company exchanged both proved and 2016:unproved oil and gas properties in the Midland Basin with unaffiliated third parties resulting in the Company recording a loss of $4 million and a gain of $20 million, respectively.
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| | Three Months Ended September 30, 2017 | Nine Months Ended September 30, 2017 |
| | Net cash receipts (payments) | | Price impact | | Net cash receipts (payments) | | Price impact |
| | (in millions) | | | | | (in millions) | | | |
Oil derivative receipts | | $ | 29 |
| | $ | 1.94 |
| per Bbl | | $ | 61 |
| | $ | 1.48 |
| per Bbl |
NGL derivative payments | | (2 | ) | | $ | (0.27 | ) | per Bbl | | (1 | ) | | $ | (0.08 | ) | per Bbl |
Gas derivative receipts | | 1 |
| | $ | 0.04 |
| per Mcf | | 1 |
| | $ | 0.01 |
| per Mcf |
Total net commodity derivative receipts | | $ | 28 |
| | | | | $ | 61 |
| | | |
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| | Three Months Ended September 30, 2016 | Nine Months Ended September 30, 2016 |
| | Net cash receipts | | Price impact | | Net cash receipts | | Price impact |
| | (in millions) | | | | | (in millions) | | | |
Oil derivative receipts | | $ | 168 |
| | $ | 13.59 |
| per Bbl | | $ | 471 |
| | $ | 13.16 |
| per Bbl |
NGL derivative receipts | | 2 |
| | $ | 0.40 |
| per Bbl | | 6 |
| | $ | 0.54 |
| per Bbl |
Gas derivative receipts | | 14 |
| | $ | 0.48 |
| per Mcf | | 56 |
| | $ | 0.59 |
| per Mcf |
Total net commodity derivative receipts | | $ | 184 |
| | | | | $ | 533 |
| | | |
The Company's open derivative contracts are subject to continuing market risk. See Note E of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" and "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for additional information regarding the Company's derivative contracts.
GainNet gain (loss) on disposition of assets net. The Company recorded net gains on the disposition of assets of nil and $205 million for the three and ninesix months ended SeptemberJune 30, 2017, respectively, as compared to $12022 primarily represents the divestment of certain undeveloped acreage and producing wells in the Midland Basin for cash proceeds of $39 million and $4$126 million, for the same respective periodsrespectively, resulting in 2016. For the nine months ended September 30, 2017, the Company'sa gain on dispositionthe divestitures of assets is primarily due to a gain of $194$35 million recognized on the sale of approximately 20,500 acres in the Martin County region of the Permian Basin. and $76 million, respectively.
See Note C3 of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Company's gain on disposition of assets.information. Oil and gas production costs. The Company recognized oil and gas
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| Three Months Ended June 30, | | | | | Six Months Ended June 30, | | | |
| 2023 | | 2022 | | Change | | | 2023 | | 2022 | | Change | |
| (in millions) | |
Oil and gas production costs | $ | 487 | | | $ | 478 | | | $ | 9 | | | | $ | 942 | | | $ | 894 | | | $ | 48 | | |
Total production costs of $152 million and $440 million during the three and nine months ended September 30, 2017, respectively,per BOE are as compared to $141 million and $438 million during the same respective periods in 2016. follows:
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| Three Months Ended June 30, | | | | | Six Months Ended June 30, | | | | | | | |
| 2023 | | 2022 | | Change | | | 2023 | | 2022 | | Change | | | | | | | |
Lease operating expense (a) | $ | 4.04 | | | $ | 3.71 | | | 9 | % | | | $ | 4.06 | | | $ | 3.59 | | | 13 | % | | | | | | | |
Gathering, processing and transportation expense (b) | 2.97 | | | 4.53 | | | (34 | %) | | | 2.96 | | | 4.20 | | | (30 | %) | | | | | | | |
Workover costs (a) | 1.07 | | | 1.02 | | | 5 | % | | | 1.11 | | | 0.90 | | | 23 | % | | | | | | | |
Net natural gas plant income (c) | (0.55) | | | (1.08) | | | (49 | %) | | | (0.66) | | | (0.97) | | | (32 | %) | | | | | | | |
| $ | 7.53 | | | $ | 8.18 | | | (8 | %) | | | $ | 7.47 | | | $ | 7.72 | | | (3 | %) | | | | | | | |
____________________
(a)Lease operating expensesexpense and workover costs represent the components of oil and gas production costs over which the Company has management control, while third-partycontrol.
(b)Gathering, processing and transportation charges representexpense represents the costcosts to (i) gather, process, transport volumes producedand fractionate the Company's gas and NGLs to a sales point. point of sale and, to a lesser extent, (ii) gather and transport certain of the Company's oil production to a point of sale.
(c)Net natural gas plant/gathering charges representplant income represents the net costs toearnings from the Company's ownership share of gas processing facilities that gather and process the Company's gas, reduced by net revenues earned from gathering and processing of third-party gasthird party gas.
The change in Company-owned facilities.
Total oil and gas production costs per BOE for the three and nine months ended September 30, 2017 decreased by six percent and 11 percent, respectively, as compared to the same respective periods in 2016. The decrease in lease operating expenses per BOE during the three and nine months ended September 30, 2017, as compared to the same respective periods in 2016, was primarily due to a greater proportion of the Company's production coming from horizontal wells in Spraberry/Wolfcamp area that have lower per BOE lease operating costs and cost reduction initiatives. The decrease in third-party transportation costs per BOE during the three and ninesix months ended SeptemberJune 30, 2017,2023, as compared to the same respective periods in 2016, was2022, is due to the following:
•Lease operating expense per BOE increased primarily due to inflationary pressures on power, chemicals and maintenance costs;
•Gathering, processing and transportation expense per BOE decreased primarily due to decreased gas processing costs as a lower proportionresult of a decrease in gas and NGL prices, which are used to value contractual volumes retained by the Company's total production being subjectgas processor as payment for their services;
•Workover costs per BOE increased primarily due to higher Eagle Ford Shale transportation costs. The netinflationary pressures on oilfield services; and
•Net natural gas plant income per BOE during the threedecreased primarily due to decreases in gas and nine months ended September 30, 2017, as compared to net natural gas plant charges for the same respective periods in 2016, is primarily reflective of increased earnings on third-party volumes that are
NGL prices.
PIONEER NATURAL RESOURCES COMPANY
processed in Company-owned facilities due to higher NGL and gas prices. The increase in workover costs per BOE during the three and nine months ended September 30, 2017, as compared to the same respective periods in 2016, was primarily due to an increase in Permian vertical well workover activity due to the improvement in commodity prices.
The following table provides the components of the Company's oil and gas production costs per BOE for the three and nine months ended September 30, 2017 and 2016:
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| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
Lease operating expenses | | $ | 4.48 |
| | $ | 4.72 |
| | $ | 4.74 |
| | $ | 5.03 |
|
Third-party transportation charges | | 0.80 |
| | 1.31 |
| | 0.87 |
| | 1.51 |
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Net natural gas plant (income) charges | | (0.29 | ) | | 0.02 |
| | (0.25 | ) | | 0.07 |
|
Workover costs | | 1.02 |
| | 0.37 |
| | 0.80 |
| | 0.30 |
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Total production costs | | $ | 6.01 |
| | $ | 6.42 |
| | $ | 6.16 |
| | $ | 6.91 |
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Production and ad valorem taxes. The Company's production
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| Three Months Ended June 30, | | | | | Six Months Ended June 30, | | | | |
| 2023 | | 2022 | | Change | | | 2023 | | 2022 | | Change | | |
| (in millions) | | |
Production and ad valorem taxes | $ | 185 | | | $ | 271 | | | $ | (86) | | | | $ | 393 | | | $ | 495 | | | $ | (102) | | | |
Production and ad valorem taxes were $53 million and $152 million during the three and nine months ended September 30, 2017, respectively,per BOE are as compared to $32 million and $97 million for the same respective periods in 2016. follows:
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| Three Months Ended June 30, | | | | | Six Months Ended June 30, | | | | |
| 2023 | | 2022 | | Change | | | 2023 | | 2022 | | Change | | |
Production taxes per BOE | $ | 2.06 | | | $ | 3.75 | | | (45 | %) | | | $ | 2.26 | | | $ | 3.50 | | | (35 | %) | | |
Ad valorem taxes per BOE | 0.80 | | | 0.88 | | | (9 | %) | | | 0.87 | | | 0.77 | | | 13 | % | | |
| $ | 2.86 | | | $ | 4.63 | | | (38 | %) | | | $ | 3.13 | | | $ | 4.27 | | | (27 | %) | | |
In general, production taxes and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, whereas production taxes are based upon current year commodity prices.
The increasechange in production taxes per BOE for the three and six months ended June 30, 2023, as compared to the same periods in 2022, is due to the aforementioned decrease in commodity prices. The change in ad valorem taxes per BOE for the three and nine months ended SeptemberJune 30, 2017,2023, as compared to the same respective periodsperiod in 2016, is primarily due2022, reflects the increasequarterly changes in commodity prices and, forestimated full year ad valorem tax purposes, the higher valuation attributable to the Company’s successful Spraberry/Wolfcamp horizontal drilling program.
taxes. The following table provides the Company's production andchange in ad valorem taxes per BOE for the three and ninesix months ended SeptemberJune 30, 2017 and 2016:
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| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
Production taxes | | $ | 1.54 |
| | $ | 1.07 |
| | $ | 1.52 |
| | $ | 1.03 |
|
Ad valorem taxes | | 0.56 |
| | 0.36 |
| | 0.61 |
| | 0.50 |
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Total production and ad valorem taxes | | $ | 2.10 |
| | $ | 1.43 |
| | $ | 2.13 |
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| $ | 1.53 |
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Depletion, depreciation and amortization expense. The Company's DD&A expense was $355 million ($14.01 per BOE) and $1.0 billion ($14.48 per BOE) for the three and nine months ended September 30, 2017, respectively, as compared to $386 million ($17.54 per BOE) and $1.1 billion ($17.73 per BOE) during the same respective periods in 2016. The change in per BOE DD&A expense during the three and nine months ended September 30, 2017,2023, as compared to the same respective periodsperiod in 2016,2022, is primarily due to a decreasean increase in prior year commodity prices that are used to determine current year ad valorem taxes.
Depletion, depreciation and amortization expense.
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| Three Months Ended June 30, | | | | | Six Months Ended June 30, | | | |
| 2023 | | 2022 | | Change | | | 2023 | | 2022 | | Change | |
| (in millions) | |
Depletion, depreciation and amortization | $ | 695 | | | $ | 620 | | | $ | 75 | | | | $ | 1,359 | | | $ | 1,234 | | | $ | 125 | | |
Total DD&A expense per BOE is as follows:
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| Three Months Ended June 30, | | | | | Six Months Ended June 30, | | | | | |
| 2023 | | 2022 | | Change | | | 2023 | | 2022 | | Change | | | |
DD&A per BOE | $ | 10.75 | | | $ | 10.60 | | | 1 | % | | | $ | 10.79 | | | $ | 10.64 | | | 1 | % | | | |
Depletion expense per BOE | $ | 10.57 | | | $ | 10.40 | | | 2 | % | | | $ | 10.60 | | | $ | 10.44 | | | 2 | % | | | |
The change in DD&A and depletion expense per BOE on oil and gas properties.
Depletion expense on oil and gas properties was $13.55 and $13.99 per BOE duringfor the three and ninesix months ended SeptemberJune 30, 2017, respectively, as compared to $17.05 and $17.21 per BOE during the same respective periods in 2016. The change in per BOE depletion expense during the three and nine months ended September 30, 2017,2023, as compared to the same respective periods in 2016,2022, is primarily due to (i) commodity price increaseshigher capital costs as a result of inflation, which marginally exceeded proved reserve additions.
Exploration and cost reduction initiatives, both of which hadabandonments expense.
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| Three Months Ended June 30, | | | | | Six Months Ended June 30, | | | | | |
| 2023 | | 2022 | | Change | | | 2023 | | 2022 | | Change | | | |
| (in millions) | | | |
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Exploration and abandonments | $ | 23 | | | $ | 11 | | | $ | 12 | | | | $ | 38 | | | $ | 24 | | | $ | 14 | | | | |
The change in exploration and abandonments expense for the effect of adding proved reserves by lengthening the economic lives of the Company's producing wellsthree and (ii) additions to proved reserves attributablesix months ended June 30, 2023, as compared to the Company's successful Spraberry/Wolfcamp horizontal drilling program.
Impairmentsame periods in 2022, is primarily related to plugging and abandonment costs exceeding their estimated abandonment liability on certain vertical wells in 2023, partially offset by the abandonment of oil and gas properties. The Company performs assessments of its long-lived assets to be held and used, including oil and gascertain unproved properties whenever events or circumstances indicatein 2022 that the carrying value of those assets may not be recoverable. ToCompany no longer planned to drill before the extent such assessments indicate a reduction ofleases expired.
During the estimated useful life or estimated future cash flows of the Company's oilsix months ended June 30, 2023 and gas properties, the carrying value may not be recoverable and therefore an impairment charge would be required to reduce the carrying value of the proved properties to their fair value.
The cash flow model2022, the Company uses to assess proved properties for impairment includes numerous assumptions. The primary factors that may affect estimates of future cash flows are (i) future reserve adjustments, both positivedrilled and negative, to proved reservesevaluated 242 and appropriate risk-adjusted probable and possible reserves, (ii) results of future drilling activities, (iii) Management's Price Outlook and (iv) increases or decreases in production costs and capital costs associated253 exploratory/extension wells, respectively, with those reserves. All inputs to the cash flow model are evaluated at each measurement date.
100 percent successfully completed as discoveries.
PIONEER NATURAL RESOURCES COMPANY
As a result of the Company's proved property impairment assessments, the Company recognized noncash impairment charges to reduce the carrying values of (i) the Raton field during the three months ended March 31, 2017 ($285 million impairment charge)See Note 6 and (ii) its West Panhandle field during the three months ended March 31, 2016 ($32 million impairment charge) to their estimated fair values. See Note D9 of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Company's proved oil and gas property impairment charges.information.Exploration and abandonments expense. The following table provides the Company's geological and geophysical costs, exploratory dry holes expenses and lease abandonments and other exploration expenses for the three and nine months ended September 30, 2017 and 2016:
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| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) |
Geological and geophysical | | $ | 17 |
| | $ | 18 |
| | $ | 59 |
| | $ | 55 |
|
Exploratory well costs | | 1 |
| | 1 |
| | 11 |
| | 1 |
|
Leasehold abandonments and other | | — |
| | — |
| | 8 |
| | 40 |
|
| | $ | 18 |
| | $ | 19 |
| | $ | 78 |
| | $ | 96 |
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The geological and geophysical expenses for the three and nine months ended September 30, 2017 and 2016 were primarily related to geological and geophysical personnel costs. During the nine months ended September 30, 2016, the Company incurred leasehold abandonments primarily related to the abandonment of unproved properties in the Permian Basin and unproved acreage in Alaska in which the Company held an overriding royalty interest.
During the nine months ended September 30, 2017, the Company drilled and evaluated 158 exploration/extension wells, 156 of which were successfully completed as discoveries. During the same period in 2016, the Company drilled and evaluated 150 exploration/extension wells, all of which were successfully completed as discoveries.
General and administrative expense. General and administrative expense for the three and nine months ended September 30, 2017 was $81 million ($3.18 per BOE) and $245 million ($3.44 per BOE), respectively, as compared to $82 million ($3.72 per BOE) and $235 million ($3.72 per BOE) for the same respective periods in 2016. The decrease in
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| Three Months Ended June 30, | | | | | Six Months Ended June 30, | | | | | | | |
| 2023 | | 2022 | | Change | | | 2023 | | 2022 | | Change | | | | | | | |
| (in millions) | | | |
Cash general and administrative expense | $ | 70 | | | $ | 78 | | | $ | (8) | | | | $ | 140 | | | $ | 144 | | | $ | (4) | | | | | | | | |
Noncash general and administrative expense | 18 | | | 10 | | | 8 | | | | 32 | | | 17 | | | 15 | | | | | | | | |
| $ | 88 | | | $ | 88 | | | $ | — | | | | $ | 172 | | | $ | 161 | | | $ | 11 | | | | | | | | |
Total general and administrative expense per BOE duringis as follows:
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| Three Months Ended June 30, | | | | | Six Months Ended June 30, | | | | | | | | |
| 2023 | | 2022 | | Change | | | 2023 | | 2022 | | Change | | | | | | | | |
Cash general and administrative expense | $ | 1.07 | | | $ | 1.33 | | | (20 | %) | | | $ | 1.11 | | | $ | 1.25 | | | (11 | %) | | | | | | | | |
Noncash general and administrative expense | 0.28 | | | 0.17 | | | 65 | % | | | 0.25 | | | 0.14 | | | 79 | % | | | | | | | | |
| $ | 1.35 | | | $ | 1.50 | | | (10 | %) | | | $ | 1.36 | | | $ | 1.39 | | | (2 | %) | | | | | | | | |
The change in cash general and administrative expense per BOE for the three and ninesix months ended SeptemberJune 30, 2017,2023, as compared to the same respective periods in 2016, was2022, is primarily due to increases of 15%(i) the aforementioned 11 percent and 13%nine percent increase in daily sales volumes, duringrespectively, due to the Company's successful Spraberry/Wolfcamp horizontal drilling program and (ii) $10 million of charitable contributions to various Ukraine humanitarian aid organizations in 2022 in response to the Russia/Ukraine conflict, partially offset by increases in labor costs. The change in noncash general and administrative expense per BOE for the three and ninesix months ended SeptemberJune 30, 2017,2023, as compared to the same respective periods in 2016.
Accretion of discount on asset retirement obligations. Accretion of discount on asset retirement obligations was $5 million and $14 million for the three and nine months ended September 30, 2017, respectively, as compared to $5 million and $14 million for the same respective periods in 2016. See Note I of Notes to Consolidated Financial Statements in "Item 1. Financial Statements" for information regarding the Company's asset retirement obligations.
Interest expense. Interest expense was $37 million and $118 million for the three and nine months ended September 30, 2017, respectively, as compared to $50 million and $161 million for the same respective periods in 2016. The decrease in interest expense during the three and nine months ended September 30, 2017, as compared to the same respective periods in 2016, was2022, is primarily due to a change in the repaymentretirement eligibility provisions for stock-based compensation awards issued to officers in 2023, which shortened the requisite service period over which expense is recognized, and changes in the market value of bothinvestments underlying the Company's 6.65% Senior Notes, which matured in March 2017, and the Company's 5.875% Senior Notes that matured in July 2016. The weighted average interest rates on the Company's indebtedness for the three and nine months ended September 30, 2017, including the effects of capitalized interest, was 5.6 percent and 5.7 percent, respectively, as compared to 5.9 percent and 6.1 percent for the same respective periods in 2016.deferred compensation obligation.
Other expense. Other expense was $58 million and $176 million for the three and nine months ended September 30, 2017, respectively, as compared to $69 million and $223 million during the same respective periods in 2016. The decrease in other expense for the three months ended September 30, 2017, as compared to the same period in 2016, was primarily due to (i) a decrease of $17 million in net losses from Company-provided fracture stimulation and related service operations that are provided to third party working interest owners and (ii) a decrease of $10 million in idle drilling and well service equipment charges, partially offset by (iii) an increase of $18 million in unused firm transportation costs. The decrease in other expense for the nine months ended September 30, 2017, as compared to the same period in 2016, was primarily due to (i) a decrease of $57 million in idle drilling and well service equipment charges and (ii) a decrease of $35 million in net losses from Company-provided fracture stimulation and related service operations that are provided to third party working interest owners, partially offset by (iii) an increase of $50 million in unused firm transportation costs.
PIONEER NATURAL RESOURCES COMPANY
The Company expects to continue to incur charges associated with excess firm gathering and transportation commitments until commodity prices improve, allowing the Company to increase its drilling activities, or the contractual obligations expire. Based on current drilling plans, the Company does not expect to incur any idle drilling rig charges. See Note L8 of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information.Income tax benefit (provision).Interest expense.
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| Three Months Ended June 30, | | | | | Six Months Ended June 30, | | | | | | | | |
| 2023 | | 2022 | | Change | | | 2023 | | 2022 | | Change | | | | | | | | |
| (in millions) | | | | |
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Interest expense | $ | 41 | | | $ | 33 | | | $ | 8 | | | | $ | 70 | | | $ | 70 | | | $ | — | | | | | | | | | |
The Company recognized an income tax benefit of $11 million and provision of $79 millionchange in interest expense for the three and ninesix months ended SeptemberJune 30, 2017, respectively,2023, as compared to an income tax benefit of $78 million and $362 million for the same respective periods in 2016. 2022, is primarily a result of (i) the issuance of 5.100% senior notes due 2026 in March 2023, (ii) the repayment of the Company's 3.950% senior notes due 2022 that matured in July 2022, (iii) the early extinguishment of the Company's 5.625% senior notes due 2027 during October 2022 and (iv) the repayment of the Company's 0.550% senior notes that matured in May 2023.
The weighted average cash interest rate on the Company's effective tax rateindebtedness for the three and ninesix months ended SeptemberJune 30, 2017 was 342023 is 2.4 percent and 322.1 percent, respectively, as compared to 1401.8 percent and 411.6 percent for the same respective periods in 2016. The Company's effective tax rate for the nine months ended September 30, 2017 differs from the U.S. statutory rate of 35 percent primarily due to recognizing excess tax benefits of $8 million during the nine months ended September 30, 2017 associated with the adoption of ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting," which requires excess tax benefits or deficiencies associated with the vesting of long-term incentive awards to be recorded as income tax expense or benefit in the statement of operations rather than as an adjustment to additional paid-in capital in the balance sheet. The Company's effective tax rates for the three and nine ended September 30, 2016 differ from the U.S. statutory rate of 35 percent primarily due to recognizing research and experimental expenditure credits of $59 million during the three months ended September 30, 2016.2022, respectively.
As of September 30, 2017 and December 31, 2016, the Company had unrecognized tax benefits of $123 million and $112 million respectively, resulting from research and experimental expenditures related to horizontal drilling and completions innovations. If all or a portion of the unrecognized tax benefit is sustained upon examination by the taxing authorities, the tax benefit will be recognized as a reduction to the Company's deferred tax liability and will affect the Company's effective tax rate in the period it is recognized. The Company expects to substantially resolve the uncertainties associated with the unrecognized tax benefit by December 2018. See Note M7 of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regardinginformation.
PIONEER NATURAL RESOURCES COMPANY
Other expense.
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| Three Months Ended June 30, | | | | | Six Months Ended June 30, | | | | | | | | |
| 2023 | | 2022 | | Change | | | 2023 | | 2022 | | Change | | | | | | | | |
| (in millions) | | | | |
Other expense | $ | 27 | | | $ | 5 | | | $ | 22 | | | | $ | 67 | | | $ | 83 | | | $ | (16) | | | | | | | | | |
The change in other expense for the three and six months ended June 30, 2023, as compared to the same periods in 2022, is primarily due to the following:
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| Three Months Ended June 30, | | | | Six Months Ended June 30, | | |
| 2023 | | 2022 | | Change | | 2023 | | 2022 | | Change |
| (in millions) |
Impairment of long-lived assets (a) | $ | 11 | | | $ | — | | | $ | 11 | | | $ | 22 | | | $ | — | | | $ | 22 | |
South Texas deficiency fee obligation (b) | $ | — | | | $ | (16) | | | $ | 16 | | | $ | — | | | $ | (16) | | | $ | 16 | |
Loss on early extinguishment of debt | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 47 | | | $ | (47) | |
____________________
(a)Impairment of long-lived assets represents the decrease in fair value of unoccupied field offices to their expected sales price or market value.
(b)Represents changes to the Company's 2022 forecasted minimum volume commitment deficiency fee obligation and receivable associated with the Company's 2019 sale of its Eagle Ford assets and other remaining assets in South Texas.
See Note 4 and Note 13 of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information. Income tax provision.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | | | | Six Months Ended June 30, | | | | | | | |
| 2023 | | 2022 | | Change | | | 2023 | | 2022 | | Change | | | | | | | |
| (in millions, except percentages) | | | |
Income tax provision | $ | (305) | | | $ | (657) | | | $ | 352 | | | | $ | (640) | | | $ | (1,209) | | | $ | 569 | | | | | | | | |
Effective tax rate | 22 | % | | 22 | % | | — | % | | | 22 | % | | 22 | % | | — | % | | | | | | | |
The change in income tax provision for the three and six months ended June 30, 2023, as compared to the same periods in 2022, is due to a decrease of $1.6 billion and $2.6 billion, respectively, in income before income taxes. The Company evaluates and updates its annual effective income tax rate on an interim basis based on current and forecasted earnings and enacted tax laws. The mix and timing of the Company's actual earnings compared to annual projections can cause interim effective tax rate fluctuations. The Company's interim effective tax rate for the three and six months ended June 30, 2023 and 2022 differed from the U.S. statutory rate of 21 percent primarily due to forecasted state income taxes.
On August 16, 2022, President Biden signed into law the IRA, which includes among other things, the CAMT. Under the CAMT, a 15 percent minimum tax will be imposed on certain adjusted financial statement income of "applicable corporations," which is effective for tax years beginning after December 31, 2022. The CAMT generally treats a corporation as an "applicable corporation" in any taxable year in which the "average annual adjusted financial statement income" of the corporation and certain of its subsidiaries and affiliates for a three-taxable-year period ending prior to such taxable year exceeds $1 billion. The Company will continue to monitor and assess any impacts of the IRA on the Company's current year tax provision and the Company's consolidated financial statements. Capital Commitments,See Note 14 of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information.Liquidity and Capital Resources and Liquidity
Capital commitments.Liquidity. The Company's primary needs forsources of short-term liquidity are (i) cash are forand cash equivalents, (ii) net cash provided by operating activities, (iii) sales of investments, (iv) unused borrowing capacity under its Credit Facility, (v) issuances of debt or equity securities and (vi) other sources, such as sales of nonstrategic assets.
The Company's short-term and long-term liquidity requirements consist primarily of (i) capital expenditures, and acquisition expenditures on(ii) acquisitions of oil and gas properties, and related vertical integration assets and facilities, payment(iii) payments of contractual obligations, including debt maturities, (iv) dividends and
PIONEER NATURAL RESOURCES COMPANY
share repurchases, (v) income taxes and (vi) working capital obligations. Funding for these cash needsrequirements may be provided by any combination of internally-generated cash flow, cashthe Company's sources of liquidity. Although the Company expects that its sources of funding will be adequate to fund its 2023 liquidity requirements, no assurance can be given that such funding sources will be adequate to meet the Company's future needs.
2023 revised capital budget. In response to improved well performance, which allows for reduced activity, and cash equivalentsimproved pricing on hand, sales of short-term and long-term investments, proceeds from divestitures of nonstrategic assets or external financing sources as discussed in "Capital resources" below.
Thecertain well costs, the Company's capital budget for 2017 is $2.752023 was revised from an expected range of $4.45 billion (excludingto $4.75 billion to an expected range of $4.375 billion to $4.575 billion of development related capital, which includes drilling and completion related activities, and the construction of tank batteries, saltwater disposal facilities and water infrastructure. The Company maintains its expected range of $150 million to $200 million of exploration, environmental and other capital, principally related to drilling four Barnett/Woodford formation wells in the Midland Basin, additional testing of the Company's enhanced oil recovery project and adding electric power infrastructure for future drilling, completions and production operations. The 2023 capital budget excludes acquisitions, asset retirement obligations, capitalized interest, geological and geophysical general and administrative costs andexpense, corporate facilities, information technology system upgrades), consisting of $2.475 billion for drilling operations and $275 million for water infrastructure, vertical integration and field facilities. vehicles.
The Company's2023 capital expenditures during the nine months ended September 30, 2017 were $2.1 billion, consisting of $1.8 billion for drilling operations (excluding acquisitions, asset retirement obligations, capitalized interest and geological and geophysical administrative costs) and $245 million for water infrastructure, vertical integration, system upgrades and other plant and equipment additions. Based on results for the nine months ended September 30, 2017 and Management's Price Outlook, the Company expects its net cash flowsbudget is expected to be funded from operating activities,cash flow and, if necessary, from cash and cash equivalents on hand sales of short-term and long-term investments, proceeds from divestitures of nonstrategic assets and, if necessary, availabilityor borrowings under the Company's Credit Facility.
Capital resources. As of June 30, 2023, the Company had $240 million of outstanding short-term borrowings under its Credit Facility, leaving $1.8 billion of unused borrowing capacity. The Credit Facility requires the maintenance of a ratio of total debt to be sufficientbook capitalization, subject to fundcertain adjustments, not to exceed 0.65 to 1.0. The Company was in compliance with all of its planned capital expenditures, acquisitionsdebt covenants as of June 30, 2023. The Company also had unrestricted cash on hand of $91 million as of June 30, 2023.
Sources and contractual obligations, including debt maturities.
Investing activities. Investing activities used $1.3 billionuses of cash during the ninesix months ended SeptemberJune 30, 2017, as compared to $3.5 billion during the nine months ended September 30, 2016. The decrease in cash used in investing activities during the nine months ended September 30, 2017,2023, as compared to the same period in 2016,2022, are as follows:
| | | | | | | | | | | | | | | | | | |
| Six Months Ended June 30, | | | |
| 2023 | | 2022 | | Change | |
| (in millions) | |
Net cash provided by operating activities | $ | 4,027 | | | $ | 5,799 | | | $ | (1,772) | | |
Net cash used in investing activities | $ | (2,466) | | | $ | (2,065) | | | $ | 401 | | |
Net cash used in financing activities | $ | (2,502) | | | $ | (5,033) | | | $ | (2,531) | | |
| | | | | | |
Operating activities. The change in net cash flow provided by operating activities during the six months ended June 30, 2023, as compared to the same period in 2022, is primarily due to (i) a decrease in oil and gas revenues, as a result of a 34 percent decrease in average realized commodity prices per BOE in 2023 due to the aforementioned volatility in worldwide oil, NGL and gas demand and (ii) an increase in the current income tax provision, partially offset by a nine percent increase in daily sales volumes due to the Company's successful Spraberry/Wolfcamp horizontal drilling program.
Investing activities. The Company's significant investing activities for the six months ended June 30, 2023 and 2022 are as follows:
•2023: The Company (i) used $2.4 billion for additions to oil and gas properties, (ii) used $69 million for additions to other assets and other property, plant and equipment and (iii) received proceeds from the disposition of assets of $23 million.
•2022: The Company (i) used $1.8 billion for additions to oil and gas properties, (ii) purchased commercial paper for $650 million, net of $2 million of discounts, (iii) received proceeds from the disposition of assets of $253 million, (iv) received proceeds from the sale of the short-term investment in Laredo common stock of $221 million and (v) used $61 million for additions to other assets and other property, plant and equipment.
Financing activities. The Company's significant financing activities during the six months ended June 30, 2023 and 2022 are as follows:
•2023: The Company (i) paid dividends of $2.1 billion, (ii) received proceeds from the March 2023 Senior Notes Offering, net of $7 million of issuance costs and discounts, of $1.1 billion, (iii) repaid $750 million associated with the maturity of investments (commercial paper, corporate bondsits 0.550% senior notes due in May 2023, (iv) repurchased $646 million of its common stock, (v) borrowed $590 million and time deposits)repaid $350 million on its Credit Facility, (vi) paid $388 million to settle exercised
PIONEER NATURAL RESOURCES COMPANY
conversion options related to the Company's Convertible Notes and (vii) received $58 million in Capped Call proceeds related to the aforementioned exercised conversion options.
•2022: The Company (i) paid dividends of $1.2$2.9 billion, during(ii) redeemed $1.3 billion of its outstanding 0.750% senior notes due 2024 and 4.450% senior notes due 2026, having aggregate principal amounts of $750 million and $500 million, respectively, (iii) repurchased $775 million of its common stock and (iv) paid $129 million of other liabilities.
Dividends. During the ninesix months ended SeptemberJune 30, 2017, as2023, the Company declared base dividends of $552 million, or $2.35 per share, compared to $255$379 million, or $1.56 per share, during the same period in 2016,2022.
Prior to April 2023, the Company had a variable dividend strategy, in addition to its base dividend program, whereby the Company paid a quarterly variable dividend of up to 75 percent of the prior quarter's free cash flow remaining after its base dividend. In April 2023, the Company modified its variable dividend strategy to return 75 percent of the prior quarter's free cash flow inclusive of its base dividend and investment purchasesshare repurchases. The modified variable dividend strategy is effective for variable dividends declared by the Board subsequent to April 2023. Free cash flow is a non-GAAP financial measure. As used by the Company, free cash flow is defined as net cash provided by operating activities, adjusted for changes in operating assets and liabilities, less capital expenditures. The Company believes this non-GAAP measure is a financial indicator of $845 million during the nineCompany's ability to internally fund acquisitions, debt maturities, dividends and share repurchases after capital expenditures. Capital expenditures exclude acquisitions, asset retirement obligations, capitalized interest, geological and geophysical general and administrative expenses, information technology capital investments, vehicles and additions to corporate facilities. During the six months ended SeptemberJune 30, 2017, as2023, the Company declared variable dividends of $1.5 billion, or $6.57 per share, compared to $2.3 billion, or $9.60 per share, during the same period in 2016. During the nine months ended September 30, 2017, the Company's expenditures for investing activities were primarily funded by net cash provided by operating activities.2022.
Dividends/distributions. During February andOn August of 2017 and March and August of 2016,1, 2023, the Board declared semiannual dividendsa quarterly base dividend of $0.04$1.25 per common share.share and a quarterly variable dividend of $0.59 per share for shareholders of record on September 6, 2023, with a payment date of September 21, 2023. Future base and variable dividends are at the discretion of the Board, and, if declared, the Board may change the current dividend amount based on the Company's outlook for commodity prices, liquidity, anddebt levels, capital resources, atfree cash flow or other factors. The Company can provide no assurance that dividends will be authorized or declared in the time.future or as to the amount of any future dividends. Any future variable dividends, if declared and paid, will fluctuate based on the Company's free cash flow and share repurchases, which will depend on a number of factors beyond the Company's control, including commodity prices and the Company's share price.
Contractual obligations, including off-balanceOff-balance sheet obligations. The Company's contractual obligations include long-term debt, operating leases, drilling commitments (primarily relatedarrangements. From time to commitments to pay day rates for contracted drilling rigs), capital
PIONEER NATURAL RESOURCES COMPANY
funding obligations, derivative obligations, firm transportation and fractionation commitments, minimum annual gathering, processing and transportation commitments and other liabilities (including postretirement benefit obligations).
From time-to-time,time, the Company enters into arrangements and transactions that can give rise to material off-balance sheet obligations of the Company. As of SeptemberJune 30, 2017,2023, the material off-balance sheet arrangements and transactions that the Company had entered into included (i) operating lease agreements, (ii) drilling commitments, (iii) firm purchase, transportation, storage and fractionation commitments, (iv)(ii) open purchase commitments and (v)(iii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable. The contractual obligations for which the ultimate settlement amounts are not fixed and determinable include (i)(a) derivative contracts that are sensitive to future changes in commodity prices, or interest rates, (ii)the Company's share price, (b) gathering, processing (primarily treating and fractionation) and transportation commitments on uncertain volumes of future throughput (iii) open delivery commitments and (iv)(c) indemnification obligations following certain divestitures.
In connection with its divestiture transactions, the Company may retain certain liabilities and provide the purchaser certain indemnifications, subject to defined limitations, which may apply to identified pre-closing matters, including matters of litigation, environmental contingencies, royalties and income taxes. The Company may also be subject to retained liabilities with respect to certain divested assets by operation of law. Upon divesting its assets, the Company may receive collateral or credit support for its exposure to such liabilities. The Company establishes reserves for the amount that exceeds the collateral or credit support received in the event that the obligation becomes likely to be paid by the Company. For example, the Company is exposed to the risk that owners and/or operators of assets purchased from the Company may become unable to satisfy plugging or abandonment obligations associated with those assets. In that event, due to operation of law, the Company may be required to assume all or part of the plugging or abandonment obligations for those assets. Although the Company may establish reserves for such liabilities, it could be required to pay additional amounts in the future and these amounts could be material. The Company does not recognize a liability if the fair value of the obligation is immaterial or the likelihood of making payments is remote.
Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other partiespersons that are reasonably likely to materially affect the Company's liquidity or availability of or requirements for capital resources. The Company expects to enter into similar contractual arrangements in the future including incremental derivative contracts and additional firm purchase, transportation, storage and transportationfractionation arrangements, in order to support the Company’sCompany's business plans.
There were no material changes to the Company's contractual obligations during the first nine months of 2017 other than the repayment of the Company's 6.65% Senior Notes in March 2017 and the commitment to a 20-year operating lease for the Company's new corporate headquarters in June 2017. Annual base rent is expected to be $33 million and lease payments are expected to commence once the building is complete, which is anticipated to occur during the second half of 2019. See
Note J10 of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information aboutinformation.
PIONEER NATURAL RESOURCES COMPANY
Convertible senior notes.In May 2020, the Company issued $1.3 billion principal amount of convertible senior notes due 2025. The Convertible Notes bear a fixed interest rate of 0.250% per year, with interest payable semiannually on May 15 and November 15. The Convertible Notes will mature on May 15, 2025, unless earlier redeemed, repurchased or converted. The Convertible Notes are unsecured obligations ranking equally in right of payment with all other senior unsecured indebtedness of the Company.
The Convertible Notes are convertible into shares of the Company's operatingcommon stock at an adjusted Conversion Rate and adjusted Conversion Price. Future declarations of quarterly base and variable dividends in excess of $0.55 per common share will cause further adjustments to the Conversion Rate and the Conversion Price pursuant to the terms of the notes indenture. Upon conversion, the Convertible Notes may be settled in cash, shares of the Company's common stock or a combination thereof, at the Company's election.
During the last 30 consecutive trading days subsequent to the third quarter of 2021 through the second quarter of 2023, the last reported sales prices of the Company's common stock exceeded 130 percent of the Conversion Price for at least 20 trading days, causing the Convertible Notes to be convertible at the option of the holders during the period from January 1, 2022 through September 30, 2023. During the six months ended June 30, 2023, the Company made total cash payments of $384 million (inclusive of settled conversion option derivatives) related to the settlement of exercised conversion options on its Convertible Notes. As of June 30, 2023, $789 million of the Convertible Notes principle balance is outstanding, of which $71 million of principal remains in the Settlement Period and will be cash settled during the third quarter of 2023. See Note 7 of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information. Contractual obligations. The Company's contractual obligations include debt, leases (primarily related to contracted drilling rigs, office facilities and other equipment), capital funding obligations, derivative obligations, firm transportation, storage and fractionation commitments, minimum annual gathering, processing and transportation commitments and other liabilities. Other joint owners in the properties operated by the Company could incur portions of the costs represented by these commitments.
Firm commitments. The Company has short-term and long-term firm purchase, gathering, processing, transportation, fractionation and storage commitments representing take-or-pay agreements, which include contractual commitments (i) to purchase sand, water and diesel for use in the Company's drilling and completion operations, (ii) with midstream service companies and pipeline carriers for future gathering, processing, transportation, fractionation and storage and (iii) with oilfield services companies that provide drilling and pressure pumping services. The Company also has open purchase commitments for inventories, materials and other property and equipment ordered, but not received, as of June 30, 2023.
Debt. As of June 30, 2023, the Company's outstanding debt is comprised of borrowings under the Credit Facility, senior notes and convertible senior notes. The senior notes and convertible senior notes issued by the Company rank equally, but are structurally subordinated to all obligations of the Company's subsidiaries. See Note 7 of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information. Operating leases. The Company's short-term and long-term lease for its new headquarters.obligations primarily relate to contracted drilling rigs, storage tanks, equipment and office facilities.
Derivative obligations. The Company's commodity, marketing and interest rate derivative contractsconversion option derivatives are periodically measured and recorded at fair value and continue to be subject to market andand/or credit risk. As of SeptemberJune 30, 2017,2023, these contracts represented net assetsliabilities of $21 million.$157 million. The ultimate liquidation value of the Company's commodity and interest ratemarketing derivatives will be dependent upon actual future commodity prices, and interest rates, which may differ materially from the inputs used to determine the derivatives' fair values as of SeptemberJune 30, 2017.2023. The ultimate liquidation of the Company's conversion option derivatives will be dependent on the Company's daily volumetric weighted average share price during the Settlement Period. See Note E4 and Note 5 of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" and "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for additional information about the Company's derivative instruments and market risk.information. Capital resources.Other liabilities. The Company's primary capital resourcesother liabilities represent current and noncurrent other liabilities that are cashprimarily comprised of litigation and cash equivalents, short-term and long-term investments, net cash provided by operating activities, proceeds from divestitures and proceeds from financing activities (principally borrowings under the Company's Credit Facility or issuances of debt or equity securities). If internal cash flows do not meet the Company's expectations, the Company may reduce its level of capital expenditures, and/or fundenvironmental contingencies, asset retirement obligations, a portion of its capital expenditures (i) using cash on hand, (ii) through sales of short-term and long-term investments, (iii) with borrowings under the Company's Credit Facility, (iv) through issuances of debt or equity securities or (v) through other sources, such as sales of nonstrategic assets.
Operating activities. Net cash provided by operating activities during the nine months ended September 30, 2017 was $1.3 billion, as compared to $959 million during the same period in 2016. The increase in net cash provided by operating activitiesfinance lease for the nine months ended September 30, 2017, as compared tocorporate headquarters office building, deferred compensation retirement plan obligations and other obligations for which neither the same period in 2016, is primarily due to increases in the Company's oil and gas revenues for the nine months ended September 30, 2017 as a result of increases in commodity prices and sales volumes, partially offset by a $472 million reduction in cash provided by commodity derivatives during the nine months ended September 30, 2017, as compared to the same period in 2016.
Financing activities. Net cash used by financing activities during the nine months ended September 30, 2017 was $521 million, as compared to net cash provided by financing activities of $2.1 billion during the same period in 2016. The decrease in net cash provided by financing activities during the nine months ended September 30, 2017, as compared to the same period in 2016, is primarily due to the Company's issuance of 19.8 million shares of common stock during 2016 for cash proceeds of $2.5 billion.
As the Company pursues its strategy, it may utilize various financing sources, including fixed and floating rate debt, convertible securities, preferred stock or common stock. The Company cannot predict the timing or ultimate outcome of any such actions as they are subject to market conditions, among other factors. The Company may also issue securities in exchange for oil and gas properties, stock or other interests in other oil and gas companies or related assets. Additional securities may be of a class preferred to common stock with respect to such matters as dividends and liquidation rights and may also have other rights and preferences as determined by the Board.
Liquidity. The Company's principal sources of short-term liquidity are cash and cash equivalents, sales of short-term and long-term investments and unused borrowing capacity under its Credit Facility. As of September 30, 2017, the Company had no outstanding borrowings under its Credit Facility, leaving $1.5 billion of unused borrowing capacity. The Company was in
PIONEER NATURAL RESOURCES COMPANY
compliance with all of its debt covenants as of September 30, 2017. The Company also had cash on hand of $636 million, short-term investments of $1.4 billion and long-term investments of $151 million as of September 30, 2017. If internal cash flows do not meet the Company's expectations, the Company may fund a portion of its capital expenditures using cash on hand, sales of short-term and long-term investments, availability under its Credit Facility, issuances of debt or equity securities or other sources, such as sales of nonstrategic assets and/or reduce its level of capital expenditures or reduce dividend payments. The Company cannot provide any assurance that needed short- term or long-term liquidity will be available on acceptable terms or at all. Although the Company expects that the combination of internal operating cash flows, cash and cash equivalents on hand, sales of short-term and long-term investments, proceeds from divestitures of nonstrategic assets and, if necessary, available capacity under the Company's Credit Facility will be adequate for the remainder of 2017 to fund planned capital expenditures, acquisitions, dividend payments and provide adequate liquidity to fund other needs, no assurancessettlement amounts nor their timings can be given that such funding sources will be adequate to meet the Company's future needs.
Debt ratings. The Company is rated as mid-investment grade by three credit rating agencies. The Company receives debt credit ratings from several of the major ratings agencies, which are subject to regular reviews. The Company believes that each of the rating agencies considers many factorsprecisely determined in determining the Company's ratings including: (i) production growth opportunities, (ii) liquidity, (iii) debt levels, (iv) asset compositionadvance. See Note 9 and (v) proved reserve mix. A reduction in the Company's debt ratings could increase the interest rates that the Company incurs on Credit Facility borrowings and could negatively impact the Company's ability to obtain additional financing or the interest rate, fees and other terms associated with such additional financing.Book capitalization and current ratio. The Company's net book capitalization as of September 30, 2017 was $11.2 billion, consisting of $636 million of cash and cash equivalents, short-term and long-term investments of $1.5 billion, debt of $2.7 billion and equity of $10.6 billion. The Company's net debt to net book capitalization increased to five percent as of September 30, 2017 from two percent as of December 31, 2016. The Company's ratio of current assets to current liabilities decreased to 1.69:1 as of September 30, 2017, as compared to 2.11:1 as of December 31, 2016, primarily due to the reclassification of the Company's 6.875% Senior Notes to a current liability.
New accounting pronouncements. The effects of new accounting pronouncements are discussed in Note B10 of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements."Statements" for additional information.
PIONEER NATURAL RESOURCES COMPANY
ItemITEM 3.Quantitative and Qualitative Disclosures About Market RiskQUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The following quantitative and qualitative disclosures about market risk are supplementary toIn the quantitative and qualitative disclosures provided innormal course of business, the Company's Annual Report on Form 10-K for the year ended December 31, 2016. As such, the information contained herein should be read in conjunctionfinancial position is routinely subject to a variety of risks, including market risks associated with the related disclosures in the Company's Annual Report on Form 10-K for the year ended December 31, 2016.
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about the Company's potential exposure to market risks. The term "market risks," insofar as it relates to currently anticipated transactions of the Company, refers to the risk of loss arising from changes in commodity prices, and interest rates. These disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators regarding how the Company views and manages ongoing market risk exposures. None ofchanges in the Company's market risk sensitive instruments are entered into for speculative purposes.
The following table reconcilesshare price, which impacts the changes that occurred in the fair values of the Company's open derivative contracts during the nine months ended September 30, 2017:settlement
|
| | | | | | | | | | | | |
| | Derivative Contract Net Assets |
| | Commodities | | Interest Rates | | Total |
| | (in millions) |
Fair value of contracts outstanding as of December 31, 2016 | | $ | (76 | ) | | $ | 6 |
| | $ | (70 | ) |
Changes in contract fair value | | 154 |
| | (1 | ) | | 153 |
|
Contract maturity receipts | | (60 | ) | | — |
| | (60 | ) |
Contract termination receipts | | (2 | ) | | — |
| | (2 | ) |
Fair value of contracts outstanding as of September 30, 2017 | | $ | 16 |
| | $ | 5 |
| | $ | 21 |
|
Interest rate sensitivity. See Note G of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" and Capital Commitments, Capital Resources and Liquidity included in "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations" for information regarding the Company's long-term debt.
PIONEER NATURAL RESOURCES COMPANY
value of convertible notes where holders have exercised their conversion option, interest rate movements on outstanding debt and credit risks. The following table providesquantitative and qualitative information is provided about financial instruments to which the Company was a party as of SeptemberJune 30, 20172023, and that are sensitive tofrom which the Company may incur future gains or losses from changes in interest rates. The table presents debt maturities by expected maturity dates, the weighted average interest rates expected to be paid on the debt given current contractual terms and market conditions and the aggregate estimated fair value ofcommodity prices, or the Company's outstanding debt. For fixed rate debt, the weighted average interest rates represent the contractual fixed rates that theshare price. The Company was obligated to periodically pay on the debt as of September 30, 2017. Although the Company had no outstanding variable rate debt as of September 30, 2017, the average variable contractual ratesdoes not enter into any financial instruments, including derivatives, for its Credit Facility (that matures in August 2020) projected forward proportionatespeculative or trading purposes.
Commodity price risk. The Company's primary market risk exposure is related to the forward yield curve for LIBOR on October 30, 2017 is presented inprice it receives from the table below.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ending December 31, | | Year Ending December 31, | | | | | | Asset (Liability) Fair Value at September 30, |
| 2017 | | 2018 | | 2019 | | 2020 | | 2021 | | Thereafter | | Total | | 2017 |
| (dollars in millions) |
Total Debt: | | | | | | | | | | | | | | | |
Fixed rate principal maturities (a) | $ | — |
| | $ | 450 |
| | $ | — |
| | $ | 450 |
| | $ | 500 |
| | $ | 1,350 |
| | $ | 2,750 |
| | $ | (2,957 | ) |
Weighted average fixed interest rate | 5.31 | % | | 5.11 | % | | 5.00 | % | | 4.42 | % | | 4.72 | % | | 5.49 | % | | | | |
Average variable interest rate | 3.01 | % | | 3.28 | % | | 3.55 | % | | 3.71 | % | |
|
| |
|
| | | | |
Interest Rate Swaps: | | | | | | | | | | | | | | | |
Notional debt amount (b) | $ | 100 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | | | $ | 5 |
|
Fixed rate payable (%) | 1.81 | % | | | | | | | | | | | | | | |
____________________
| |
(a) | Represents maturitiessale of principal amounts, excluding debt issuance costs and debt issuance discounts. |
| |
(b) | As of September 30, 2017, the Company was party to interest rate derivative contracts whereby the Company will receive the three-month LIBOR rate for the 10-year period from December 2017 through December 2027 in exchange for paying a fixed interest rate of 1.81 percent on a notional amount of $100 million on December 15, 2017. Subsequent to September 30, 2017, the Company liquidated its interest rate derivative contracts for cash proceeds of $5 million. |
Commodity derivative instruments and price sensitivity. The following table provides information about the Company's oil, NGL and gas production. Realized pricing is volatile and is determined by market prices that fluctuate with changes in supply and demand for these products throughout the world. The price the Company receives for its production depends on many factors outside of the control of the Company, including differences in commodity pricing at the point of sale versus market index prices. The Company's exposure to price volatility impacts the funds available to be used in its capital program and for general working capital needs, debt obligations, dividends and share repurchases, among other uses. The Company mitigates its commodity price risk by (i) maintaining financial flexibility with a strong balance sheet, (ii) using derivative financial instruments and (iii) sales of purchased commodities.
Commodity price derivatives. The Company primarily utilizes derivative contracts to reduce the effect of price volatility on the commodities the Company produces and sells. The Company's decision on the quantity and price at which it executes commodity derivative contracts, if it so chooses, is based in part on its view of current and future market conditions. The Company may choose not to enter into derivative positions for expected production if the commodity price forecast for certain time periods is deemed to be unfavorable. Additionally, the Company may choose to liquidate existing derivative positions prior to the expiration of their contractual maturity in order to monetize gain positions or minimize loss positions if it is anticipated that were sensitivethe commodity price forecast is expected to changes in oil, NGL and gas prices asimprove. Proceeds, if any, can be used for the purpose of September 30, 2017. Although mitigated byfunding the Company's capital program, general working capital needs, debt obligations, dividends and share repurchases, among other uses. While derivative activities, declines in oil, NGL and gas prices would reducepositions limit the Company's revenues.downside risk of adverse price movements, they also limit future revenues from upward price movements.
TheAs of June 30, 2023, the Company managesdid not have any material outstanding commodity price risk with derivative contracts, such as swap contracts, collar contracts and collar contracts with short put options. Swap contracts provide a fixed price for a notional amount of sales volumes. Collar contracts provide minimum ("floor" or "long put") and maximum ("ceiling") prices on a notional amount of sales volumes, thereby allowing some price participation if the relevant index price closes above the floor price. Collar contracts with short put options differ from other collar contracts by virtue of the short put option price, below which the Company's realized price will exceed the variable market prices by the long put-to-short put price differential.
contracts. See
Notes D and ENote 5 of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for a description of the accounting procedures followed byCompany's open derivative positions and additional information. Sales of purchased commodities. The Company enters into pipeline capacity commitments in order to secure available oil, NGL and gas transportation capacity from the Company's areas of production and to secure diesel supply from the Gulf Coast. The Company also enters into purchase commitments to secure sand supply for its derivative financial instrumentsthe Company's operations in the Midland Basin. The Company enters into purchase transactions with third parties and for specific information regarding the termsseparate sale transactions with third parties to diversify a portion of the Company's derivative financial instrumentsoil and gas sales to (i) Gulf Coast refineries, (ii) Gulf Coast and West Coast gas markets and (iii) international oil markets, and to satisfy unused gas pipeline capacity commitments. The Company periodically sells diesel and sand to unaffiliated third parties in the Permian Basin if it has supply in excess of its operational needs.
Marketing derivatives. The Company uses marketing derivatives to diversify its oil pricing to Gulf Coast and international markets.As of June 30, 2023, the Company's marketing derivatives reflect long-term marketing contracts whereby the Company agreed to purchase and simultaneously sell, at an oil terminal in Midland, Texas, (i) 50 thousand barrels of oil per day beginning January 1, 2021 and ending December 31, 2026, (ii) 40 thousand barrels of oil per day beginning May 1, 2022 and ending April 30, 2027 and (iii) 30 thousand barrels of oil per day beginning August 1, 2022 and ending July 31, 2027.
The price the Company pays to purchase the oil volumes under the purchase contracts is based on a Midland WTI price and the price the Company receives for the oil volumes sold is the WASP that a non-affiliated counterparty receives for selling oil through a Gulf Coast storage and export facility at prices that are sensitivehighly correlated with Brent oil prices during the same month of the purchase. Based on the form of the long-term marketing contracts, the Company accounts for the contracts as derivative instruments not designated as hedges.
The Company could experience mark-to-market fluctuations in the fair value of its marketing derivatives based on changes in (i) the differential between Midland WTI and Brent and (ii) the WASP Differential Deduction if it deviates from historical levels. For example, a 10 percent increase or decrease in the differential between Midland WTI and Brent would impact the fair value of the Company's marketing derivatives recorded by approximately $50 million and a 10 percent increase or decrease in the WASP Differential Deduction would impact the fair value of the Company's marketing derivatives recorded by approximately $25 million as of June 30, 2023. See Note 4 and Note 5 of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information. Company share price risk. When holders of the Company's Convertible Notes exercise their conversion option, the Company is subject to market risks related to changes in oil, NGL or gas prices.
the Company's share price that occur during the Settlement Period. See
PIONEER NATURAL RESOURCES COMPANY
Note 4,Note 5 and Note 7 of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information. |
| | | | | | | | | | | | | | | |
| 2017 | | Year Ending December 31, | | Asset (Liability) Fair Value at September 30, 2017 (a) |
| Fourth Quarter | | 2018 | | 2019 | |
| | | | | | | (in millions) |
Oil Derivatives: | | | | | | | |
Average daily notional Bbl volumes: | | | | | | | |
Collar contracts (b) | 6,000 |
| | — |
| | — |
| | $ | 1 |
|
Weighted average ceiling price per Bbl | $ | 70.40 |
| | $ | — |
| | $ | — |
| | |
Weighted average floor price per Bbl | $ | 50.00 |
| | $ | — |
| | $ | — |
| | |
Collar contracts with short puts (c) | 155,000 |
| | 150,781 |
| | — |
| | $ | 14 |
|
Weighted average ceiling price per Bbl | $ | 62.12 |
| | $ | 57.70 |
| | $ | — |
| | |
Weighted average floor price per Bbl | $ | 49.82 |
| | $ | 47.39 |
| | $ | — |
| | |
Weighted average short put price per Bbl | $ | 41.02 |
| | $ | 37.35 |
| | $ | — |
| | |
Average forward NYMEX oil prices (d) | $ | 54.15 |
| | $ | 53.98 |
| | $ | — |
| | |
Midland-Cushing index swap contracts (e) | 6,630 |
| | — |
| | — |
| | — |
|
Weighted average price differential per Bbl | $ | (1.09 | ) | | $ | — |
| | $ | — |
| | |
Average forward basis differential prices (f) | $ | 0.44 |
| | $ | — |
| | $ | — |
| | |
NGL Derivatives (g): | | | | | | | |
Ethane collar contracts (Bbl) (h) | 3,000 |
| | — |
| | — |
| | $ | — |
|
Weighted average ceiling price per Bbl | $ | 11.83 |
| | $ | — |
| | $ | — |
| | |
Weighted average floor price per Bbl | $ | 8.68 |
| | $ | — |
| | $ | — |
| | |
Average forward ethane prices (d) | $ | 11.55 |
| | $ | — |
| | $ | — |
| | |
Ethane basis swap contracts (MMBtu) (i) | 6,920 |
| | 6,920 |
| | 6,920 |
| | $ | — |
|
Weighted average price differential per MMBtu | $ | 1.60 |
| | $ | 1.60 |
| | $ | 1.60 |
| | |
Average forward NYMEX gas prices (d) | $ | 2.97 |
| | $ | 3.00 |
| | $ | 2.91 |
| | |
Gas Derivatives: | | | | | | | |
Average daily notional MMBtu volumes: | | | | | | | |
Swap contracts (j) | — |
| | 30,000 |
| | — |
| | $ | — |
|
Weighted average fixed price per MMBtu | $ | — |
| | $ | 3.08 |
| | $ | — |
| | |
Collar contracts with short puts | 300,000 |
| | 62,329 |
| | — |
| | $ | 2 |
|
Weighted average ceiling price per MMBtu | $ | 3.60 |
| | $ | 3.56 |
| | $ | — |
| | |
Weighted average floor price per MMBtu | $ | 2.96 |
| | $ | 2.91 |
| | $ | — |
| | |
Weighted average short put price per MMBtu | $ | 2.47 |
| | $ | 2.37 |
| | $ | — |
| | |
Average forward NYMEX gas prices (d) | $ | 2.97 |
| | $ | 3.00 |
| | $ | — |
| | |
Basis swap contracts: | | | | | | | $ | (1 | ) |
Mid-Continent index swap contracts (k) | 45,000 |
| | — |
| | — |
| | |
Weighted average fixed price per MMBtu | $ | (0.32 | ) | | $ | — |
| | $ | — |
| | |
Average forward basis differential prices (l) | $ | (0.25 | ) | | $ | — |
| | $ | — |
| | |
Permian Basin index swap contracts (m) | 26,522 |
| | 51,671 |
| | 70,000 |
| | |
Weighted average fixed price per MMBtu | $ | 0.30 |
| | $ | 0.30 |
| | $ | 0.30 |
| | |
Average forward basis differential prices (n) | $ | 0.63 |
| | $ | 0.38 |
| | $ | 0.38 |
| | |
___________________
| |
(a) | In accordance with Financial Accounting Standards Board ASC 210-20 and ASC 815-10, the Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net derivative assets or net derivative liabilities, as the case may be. The net asset and liability amounts shown above have been provided on a commodity contract-type basis, which may differ from their master netting arrangements classifications. |
| |
(b) | Subsequent to September 30, 2017, the Company entered into additional collar contracts for 3,000 Bbls per day of 2018 production with a ceiling price of $58.05 per Bbl and a floor price of $45.00 per Bbl. |
| |
(c) | Subsequent to September 30, 2017, the Company entered into additional collar contracts with short puts for 2,000 Bbls per day of 2018 production with a ceiling price of $59.25 per Bbl, a floor price of $45.00 per Bbl and a short put price of $35.00 per Bbl. |
| |
(d) | The average forward NYMEX oil, ethane and gas prices are based on October 30, 2017 market quotes. |
| |
(e) | Represents swap contracts that fix the basis differential between Midland, Texas oil prices and WTI oil prices at Cushing, Oklahoma. |
PIONEER NATURAL RESOURCES COMPANY
| |
(f) | The average forward basis differential prices are based on October 30, 2017 market quotes for basis differentials between Midland, Texas oil prices and WTI prices at Cushing, Oklahoma. |
| |
(g) | Subsequent to September 30, 2017, the Company entered into propane swap contracts for 2,500 Bbls per day of November and December 2017 production with a fixed price of $37.80 per Bbl. |
| |
(h) | Represent collar contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices. |
| |
(i) | Represent basis swap contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices. The basis swap contracts fix the basis differential on a HH MMBtu equivalent basis. The Company will receive the HH price plus the price differential on 6,920 MMBtu per day, which is equivalent to 2,500 Bbls per day of ethane. |
| |
(j) | Subsequent to September 30, 2017, the Company entered into additional swap contracts for 70,000 MMBtu per day of April through December 2018 production with a price of $3.00 per MMBtu. |
| |
(k) | Represent swap contracts that fix the basis differentials between the index prices at which the Company sells its Mid-Continent gas and the HH index price used in collar contracts with short puts. |
| |
(l) | The average forward basis differential prices are based on October 30, 2017 market quotes for basis differentials between the Mid-Continent index prices and the NYMEX-quoted forward prices. |
| |
(m) | Represent swap contracts that fix the basis differentials between Permian Basin index prices and southern California index prices for Permian Basin gas forecasted for sale in southern California. Subsequent to September 30, 2017, the Company entered into additional basis swap contracts for (i) 20,000 MMBtu per day of November 2017 through March 2018 production with a price of $0.49 per MMBtu and (ii) 10,000 MMBtu per day of 2019 production with a price of $0.32 per MMBtu. |
| |
(n) | The average forward basis differential prices are based on October 30, 2017 market quotes for basis differentials between Permian Basin index prices and southern California index prices. |
Marketing derivatives. Periodically,June 30, 2023, the Company enters into buyhad $240 million of variable rate debt outstanding under the Credit Facility and sell marketing arrangements$5.1 billion of fixed rate debt outstanding. The variable rate debt outstanding under the Company's Credit Facility is benchmarked to fulfill firm pipeline transportation commitments. Associated with these marketing arrangements,SOFR, and is therefore exposed to interest rate risk. Assuming no change in the amount of variable rate debt outstanding, a 100 basis point increase or decrease in the average interest rate would impact annual interest expense by approximately $2 million. The Company has no interest rate derivative instruments outstanding; however, it may enter into index swaps thatderivative instruments in the future to mitigate priceinterest rate risk. AsSee Note 4 and Note 7 of September 30, 2017,Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information.Credit risk. The Company's primary concentration of credit risks are associated with the collection of receivables resulting from the sale of oil and gas production and purchased commodities, and the risk of a counterparty's failure to meet its obligations under derivative contracts with the Company.
The Company's commodities are sold to various purchasers who must be prequalified under the Company's credit risk policies and procedures. The Company monitors exposure to counterparties primarily by reviewing credit ratings, financial criteria and payment history. Where appropriate, the Company was partyobtains assurances of payment, such as a guarantee by the parent company of the counterparty, a letter of credit or other credit support. Historically, the Company's credit losses on commodity receivables have not been material.
The Company uses credit and other financial criteria to (i) oil index swap contracts for 10,000 Bbls per dayevaluate the credit standing of, November and December 2017 transportation commitments with a price differential of $4.18 per Bbl between NYMEX WTI and Louisiana Light Sweet oil ("LLS") and (ii) oil index swap contracts for 10,000 Bbls per day of January through August 2018 transportation commitments with a price differential of $3.18 per Bbl between NYMEX WTI and LLS. As of September 30, 2017, these positions hadto select, counterparties to its derivative instruments. Although the Company does not obtain collateral or otherwise secure the fair value of nil. Based on October 30, 2017 market quotes,its derivative instruments, associated credit risk is mitigated by the average forward basis differential price was $6.05 per BblCompany's credit risk policies and procedures.
The Company has entered into International Swap Dealers Association Master Agreements ("ISDA Agreements") with each of its commodity derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with right of set off upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative contract, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note 5 of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for December 2017 and $4.50 per Bbl for January through August 2018 between the relevant quoted forward oil index prices.additional information.
PIONEER NATURAL RESOURCES COMPANY
ItemITEM 4.Controls and ProceduresCONTROLS AND PROCEDURES
Evaluation of disclosure controls and procedures. The Company's management, with the participation of its principal executive officer and principal financial officer, have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the "Exchange Act"), the effectiveness of the Company's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this Report. Based on that evaluation, the principal executive officer and principal financial officer concluded that the Company's disclosure controls and procedures were effective, as of the end of the period covered by this Report, in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, including that such information is accumulated and communicated to the Company's management, including the principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.
Changes in internal control over financial reporting. There have been no changes into the Company's internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the three months ended SeptemberJune 30, 20172023 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.
PIONEER NATURAL RESOURCES COMPANY
PART II. OTHER INFORMATION
ItemITEM 1.Legal Proceedings
LEGAL PROCEEDINGS
The Company is party to the legal proceeding described in Note J of Notes to Consolidated Financial Statements included in "Part I, Item 1. Financial Statements." The Company is also party to various proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to these proceedings and claims will not have a material adverse effect on the Company's consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations.
On May 18, 2023, the Company received a Notice of Violation and Opportunity to Confer from the Environmental Protection Agency ("EPA") alleging violations of the Clean Air Act at certain of its operated locations. The Company is engaged in discussions with the EPA regarding a resolution of the alleged violations. The Company does not believe that the
PIONEER NATURAL RESOURCES COMPANY
resolution of this matter will have a material adverse impact on the Company's consolidated financial position as a whole or on its liquidity, capital resources or future results of operations, but the resolution of the matter may result in penalties that exceed $300,000.
Item 1A. Risk FactorsITEM 1A.RISK FACTORS
In addition to the information set forth in this Report, the risks that are discussed in the Company's Annual Report on Form 10-K for the year ended December 31, 2016,2022, under the headings "Part I, Item 1. Business – Competition, Markets and Regulations," "Part I. Item 1. Business - Regulation," "Part I, Item 1A. Risk Factors" andFactors," "Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk,"Risk" should be carefully considered, as such risks could materially affect the Company's business, financial condition or future results. There has been no material change in the Company's risk factors from thosethat were described in the Company's 2022 Annual Report on Form 10-K.
These risks are not the only risks facing the Company. Additional risks and uncertainties not currently known to the Company or that it currently deems to be immaterial also may have a material adverse effect on the Company's business, financial condition or future results.
ItemITEM 2.Unregistered Sales of Equity Securities and Use of ProceedsUNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
The following table summarizesPurchases of the Company's purchases of treasurycommon stock under plans or programsare as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, 2023 |
Period | | Total Number of Shares Purchased (a) | | Average Price Paid per Share | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | | Approximate Dollar Amount of Shares that May Yet Be Purchased under Plans or Programs (b) |
April 1-30, 2023 | | 906 | | | $ | 222.48 | | | — | | | $ | 4,000,000,000 | |
May 1-31, 2023 | | 478,297 | | | $ | 207.91 | | | 478,232 | | | $ | 3,900,572,356 | |
June 1-30, 2023 | | 122,643 | | | $ | 204.04 | | | 122,510 | | | $ | 3,875,575,094 | |
| | 601,846 | | | | | 600,742 | | | |
__________________
(a)Includes shares withheld from employees in order for employees to satisfy income tax withholding payments related to share-based awards that vested during the period.
(b)In April 2023, the Board authorized a new $4 billion common stock repurchase program to replace the prior $4 billion common stock repurchase program authorized in February 2022. The stock repurchase program has no time limit and may be modified, suspended or terminated at any time by the Board.
ITEM 5.OTHER INFORMATION
The Company was not informed by any of its directors or officers of the adoption or termination of a "Rule 10b5-1 trading arrangement" or "non-Rule 10b5-1 trading arrangement," as those terms are defined in Regulation S-K, Item 408, during the three months ended SeptemberJune 30, 2017:2023.
|
| | | | | | | | | | | | | | |
Period | | Total Number of Shares Purchased (a) | | Average Price Paid per Share | | Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs | | Approximate Dollar Amount of Shares that May Yet Be Purchased under Plans or Programs |
July 2017 | | 225 |
| | $ | 161.75 |
| | — |
| | |
August 2017 | | 2,216 |
| | $ | 133.79 |
| | — |
| | |
September 2017 | | 139 |
| | $ | 131.78 |
| | — |
| | |
Total | | 2,580 |
| | $ | 136.12 |
| | — |
| | $ | — |
|
____________________
| |
(a) | Consists of shares purchased from employees in order for the employee to satisfy tax withholding payments related to share-based awards that vested during the period. |
Item 4.Mine Safety Disclosures
The Company's sand mines are subject to regulation by the Federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977, as amended by the Mine Improvement and New Emergency Response Act of 2006. Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95.1 to this Report.
PIONEER NATURAL RESOURCES COMPANY
ItemITEM 6.Exhibits
Exhibits
| | | | | | | | | | |
Exhibit Number | | | | Description |
4.1 | | | | |
| | | | |
Exhibit
Number10.1 | | | | Description |
| | | | |
10.1 | | (a) — | | EighthSecond Amendment dated as of May 26, 2023, to Pioneer USA 401(k)the Credit Agreement dated October 24, 2018, among the Company, as the Borrower, Wells Fargo Bank, National Association, as Administrative Agent, Wells Fargo Bank, National Association, Bank of America, N.A. and Matching Plan dated August 28, 2017.JPMorgan Chase Bank, N.A., as Syndication Agents, and certain other agents and lenders party thereto (incorporated by reference to exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 31, 2023). |
| | | | |
12.131.1 (a) | | (a) — | | |
| | | | |
31.1 | | (a) — | | |
| | | | |
31.2 (a) | | (a) — | | |
| | | | |
32.1 (b) | | (b) — | | |
| | | | |
32.2 (b) | | (b) — | | |
| | | | |
95.1101.INS (a) | | (a) — | | Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. |
| | | | |
101.INS101.SCH (a) | | (a) — | | XBRL Instance Document. |
| | | | |
101.SCH | | (a) — | | Inline XBRL Taxonomy Extension Schema.Schema Document. |
| | | | |
101.CAL (a) | | (a) — | | Inline XBRL Taxonomy Extension Calculation Linkbase Document. |
| | | | |
101.DEF (a) | | (a) — | | Inline XBRL Taxonomy Extension Definition Linkbase Document. |
| | | | |
101.LAB (a) | | (a) — | | Inline XBRL Taxonomy Extension Label Linkbase Document. |
| | | | |
101.PRE (a) | | (a) — | | Inline XBRL Taxonomy Extension Presentation Linkbase Document. |
_____________
| | | | |
(a)104 | Filed herewith. | | | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). |
____________________
| | | | | |
(b)(a) | Filed herewith. |
(b) | Furnished herewith. |
H | Executive Compensation Plan or Arrangement. |
* | Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Company agrees to furnish to the SEC a copy of any omitted schedule upon request. |
PIONEER NATURAL RESOURCES COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned hereto duly authorized.
| | | | | | | | | | | | | | |
| | PIONEER NATURAL RESOURCES COMPANY |
| | | | |
August 1, 2023 | | PIONEER NATURAL RESOURCES COMPANYBy: | | /s/ Neal H. Shah |
| | | | Neal H. Shah |
Date: November 3, 2017 | | By: | | /s/ RICHARD P. DEALY |
| | | | Richard P. Dealy, |
| | | | Executive Vice President and Chief Financial Officer |
| | | | |
Date: November 3, 2017August 1, 2023 | | By: | | /s/ MARGARET M. MONTEMAYORChristopher L. Washburn |
| | | | Margaret M. Montemayor,Christopher L. Washburn |
| | | | Vice President and Chief Accounting Officer |