DALLAS--(BUSINESS WIRE)--Pioneer Natural Resources Company (NYSE:PXD) (“Pioneer” or “the Company”) today reported financial and operating results for the quarter ended December 31, 2015, and announced the Company’s capital program for 2016.
Pioneer reported a fourth quarter net loss attributable to common stockholders of $623 million, or $4.17 per diluted share. Without the effect of noncash mark-to-market derivative losses and other unusual items, adjusted results for the fourth quarter were a net loss of $27 million after tax, or $0.18 per diluted share.
Fourth quarter and other recent highlights included:
- producing 215 thousand barrels oil equivalent per day (MBOEPD) in the fourth quarter, of which 53% was oil; production grew by 4 MBOEPD, or 2%, compared to the third quarter of 2015 and was at the top end of Pioneer’s revised fourth quarter production guidance range of 213 MBOEPD to 215 MBOEPD;
- producing 204 MBOEPD in 2015, an increase of 22 MBOEPD, or 12%, from 2014 (reflects Alaska, Barnett Shale and Hugoton divestitures in 2014 as discontinued operations); oil production grew by 18 thousand barrels oil per day (MBOPD), or 21%, on a comparable basis; oil production represented 52% of Pioneer’s total 2015 production, up from 48% in 2014; fourth quarter and full-year 2015 production growth were primarily driven by the Company’s Spraberry/Wolfcamp horizontal drilling program;
- delivering 273% drillbit reserve replacement by adding proved reserves of 210 million barrels oil equivalent (MMBOE) from discoveries, extensions and technical revisions of previous estimates at a drillbit finding and development cost of $10.18 per barrel oil equivalent (BOE) (excludes negative price revisions of 269 MMBOE and reserves added from acquisitions of 1 MMBOE);
- placing 44 horizontal wells on production in the Spraberry/Wolfcamp during the fourth quarter as expected; early production results from 35 wells in the northern area and nine wells in the southern Wolfcamp joint venture area are exceeding expectations as a result of the Company’s completion optimization program;
- realizing significant capital efficiency gains in the Spraberry/Wolfcamp; cost per lateral foot and well productivity improved significantly from the fourth quarter of 2014 to the fourth quarter of 2015 as a result of service cost reductions, efficiency gains and the completion optimization program;
- issuing $500 million of Senior Notes due 2021 at an interest rate of 3.45% and $500 million of Senior Notes due 2026 at an interest rate of 4.45% in December to fund the repayment of 2016 and 2017 maturities; and
- working with midstream partners to have oil export facilities along the Gulf Coast operational by the middle of 2016 to take advantage of future export opportunities now that the oil export ban has been lifted.
Pioneer’s plans for 2016 in response to the outlook for continuing weak oil prices are summarized below:
- reducing horizontal drilling activity by 50% from 24 rigs at year-end 2015 to 12 rigs by the middle of 2016, while still growing 2016 production by 10%+ and preserving the Company’s strong balance sheet and cash position; the Eagle Ford Shale rig count is being reduced from six rigs at year-end 2015 to zero rigs during the first quarter, with two rigs released in January as previously announced; the rig count in the southern Wolfcamp joint venture area is being reduced from four rigs at year-end 2015 to zero rigs by the middle of the year and the rig count in the northern Spraberry/Wolfcamp is being reduced from 14 rigs at year-end 2015 to 12 rigs during the first quarter for capital preservation, with one rig already released; the 12-rig program will allow the Company to continue to progress its completion optimization program in the northern Spraberry/Wolfcamp at favorable returns;
- relocating Pioneer’s two Eagle Ford Shale pressure pumping fleets to the Spraberry/Wolfcamp;
- planning capital expenditures for 2016 of $2.0 billion as a result of the reduction in drilling activity and vertical integration spending, down from Pioneer’s preliminary forecast of $2.4 billion to $2.6 billion and 2015 actual spending of $2.2 billion; of the $2.0 billion, $1.85 billion is for drilling and completions (includes tank batteries, saltwater disposal facilities and gas processing facilities) and $150 million is for vertical integration, systems upgrades and field facilities;
- protecting the Company’s cash flow through strong commodity derivative positions, with (i) oil derivative coverage of approximately 85% for 2016 and 20% for 2017 and (ii) gas derivative coverage of approximately 70% for 2016; and
- maintaining a strong investment grade balance sheet, with financial resources in place that are expected to enable the Company to grow production and fund its expected capital program through 2017 without increasing debt; resources include forecasted cash flow, cash on hand at the end of 2015 of $0.4 billion (excludes proceeds from the December notes offering), proceeds from the Company’s January equity offering of $1.6 billion (includes exercise by underwriters of overallotment option) and an additional $0.5 billion to be received in July 2016 from the sale of Eagle Ford Shale midstream business; results in year-end 2015 pro forma net debt-to-2016 operating cash flow of 0.2 times.
Scott D. Sheffield, Chairman and CEO, stated, “The performance from our Spraberry/Wolfcamp horizontal drilling program continues to be outstanding. Our strong balance sheet, derivatives position and improving capital efficiency are allowing us to continue to grow and bring forward the inherent net asset value associated with this world class asset during a period of low commodity prices. We have the financial flexibility to prudently manage through the current commodity price downturn or quickly ramp up drilling activity when prices improve.”
Mark-To-Market Derivative Gains and Unusual Items Included in Fourth Quarter 2015 Earnings
Pioneer’s fourth quarter earnings included noncash mark-to-market losses on derivatives of $13 million after tax, or $0.09 per diluted share.
Fourth quarter earnings also included a net loss of $583 million after tax, or $3.90 per diluted share, related to the following unusual items:
- a noncash charge of $542 million after tax, or $3.63 per diluted share, associated with the impairment of proved properties in the Eagle Ford Shale and
- other noncash impairments totaling $41 million after tax, or $0.27 per diluted share, primarily associated with excess vertical pipe inventory.
Spraberry/Wolfcamp Operations Update and 2016 Outlook
Pioneer is the largest acreage holder in the Spraberry/Wolfcamp, with approximately 600,000 gross acres in the northern portion of the play and approximately 200,000 gross acres in the southern Wolfcamp joint venture area. Pioneer’s contiguous acreage position and substantial resource potential allow for decades of drilling horizontal wells with lateral lengths ranging from 7,500 feet to 10,000 feet.
In the northern Spraberry/Wolfcamp, horizontal well performance continues to improve. The Company placed 22 horizontal Wolfcamp B interval wells on production during the fourth quarter. Early production results from these wells are on average displaying Pioneer’s strongest horizontal well performance to date and tracking well above a 1 MMBOE estimated ultimate recovery (EUR) type curve. The wells, which had an average perforated lateral length of 8,400 feet, delivered an average 24-hour peak production rate of approximately 2,200 barrels oil equivalent per day (BOEPD), with 80% oil content. All of the wells benefited from Pioneer’s completion optimization program. This program combines longer laterals with optimized stage length, clusters per stage, fluid volumes and proppant concentrations.
Pioneer also placed two Wolfcamp A interval wells and 11 Lower Spraberry Shale wells on production in the northern Spraberry/Wolfcamp during the fourth quarter. The two Wolfcamp A wells, which were placed on production at year end, had an average perforated lateral length of 9,450 feet and benefited from optimized completions. They delivered an average 24-hour peak production rate of approximately 1,570 BOEPD, with 80% oil content. The wells were recently placed on gas lift. The 11 Lower Spraberry Shale wells, which had an average perforated lateral length of 8,850 feet, have delivered to date an average 24-hour peak production rate of approximately 1,110 BOEPD, with 84% oil content. Five of the 11 wells have not yet achieved their 24-hour peak production rates. The wells are on average tracking close to a 1 MMBOE EUR type curve. Completions were optimized on nine of the 11 Lower Spraberry Shale wells.
During the third quarter of 2015, Pioneer placed 30 horizontal Wolfcamp interval wells on production in the northern Spraberry/Wolfcamp (28 wells in the Wolfcamp B interval and 2 wells in the Wolfcamp A interval). Completions were optimized (stage length, clusters per stage, fluid volumes and proppant concentrations) on approximately 65% of these wells. Production results from all of these wells (optimized and non-optimized) continue to exceed a 1 MMBOE EUR type curve.
Horizontal well performance also continues to improve in the southern Wolfcamp joint venture area. The Company placed nine wells on production during the fourth quarter in this area. Early production results from the eight Wolfcamp B interval wells that were placed on production are on average tracking above a 1 MMBOE EUR type curve. These wells, which had an average perforated lateral length of 9,070 feet, delivered an average 24-hour peak production rate of approximately 1,630 BOEPD, with 83% oil content. Production from the one Wolfcamp A interval well that was placed on production is tracking above an 800 MBOE EUR type curve. This well, which had an average perforated lateral length of 10,250 feet, delivered an average 24-hour peak production rate of approximately 980 BOEPD, with 79% oil content. Completions were optimized in all of the wells (stage length, clusters per stage, fluid volumes and proppant concentrations).
The Company is realizing significant capital efficiency gains in the Spraberry/Wolfcamp. For example, the drilling and completion cost per perforated lateral foot for all horizontal Wolfcamp B interval wells placed on production in the northern Spraberry/Wolfcamp area between the fourth quarter of 2014 and the fourth quarter of 2015 has decreased by 30% on average as a result of cost reductions and efficiency gains. During this same period, well productivity for these same Wolfcamp B interval wells over the first 90 days of production has improved significantly as a result of Pioneer’s completion optimization program. This is evidenced by an approximate 50% increase in the average 90-day cumulative production per well for the Wolfcamp B interval wells from the fourth quarter of 2014 to the fourth quarter of 2015. Stated differently, the average daily production rate for the 22 Wolfcamp B interval wells in the fourth quarter of 2015 averaged approximately 1,250 BOEPD for their first 90 days on production compared to an average of approximately 830 BOEPD for the 20 Wolfcamp B interval wells placed on production in the fourth quarter of 2014.
Pioneer expects to place approximately 230 horizontal wells on production in the Spraberry/Wolfcamp area during 2016. Of these wells, approximately 190 wells will be in the northern area and 40 wells will be in the southern Wolfcamp joint venture area. Approximately 60% of the wells will be drilled in the Wolfcamp B interval, 25% in the Wolfcamp A interval and 15% in the Lower Spraberry Shale interval. For comparison, the Company placed 197 horizontal wells on production during 2015, of which 111 wells were in the northern area and 86 wells were in the southern Wolfcamp joint venture area. Approximately 70% of the wells were drilled in the Wolfcamp B interval, with the remainder split among the Wolfcamp A, Wolfcamp D and Lower Spraberry Shale intervals.
The Company is forecasting EURs for its 2016 drilling program ranging from 800 MBOE to 1.2 MMBOE. EURs are benefiting from longer lateral lengths and Pioneer’s completion optimization program that commenced in 2015 and includes increased fluid volumes and proppant concentrations, reduced stage lengths and additional clusters per stage. The current cost to drill and complete a horizontal well is approximately $7.5 million to $8.0 million, assuming average perforated lateral lengths of approximately 9,000 feet and utilization of the 2015 optimized completion design as the standard design for 2016. The Company expects to continue to further optimize its completion designs during 2016.
Despite weak commodity prices, the 2016 drilling program in the northern Spraberry/Wolfcamp area is expected to continue to deliver favorable internal rates of return, with returns up to 30% expected at current strip commodity prices. These returns, which include tank battery and saltwater disposal facility costs, are benefiting from continuing cost reduction efforts, drilling and completion efficiency gains and well productivity improvements.
The Company’s horizontal drilling program continues to drive production growth, with total Spraberry/Wolfcamp area production growing by 26 MBOEPD, or 27%, in 2015 compared to 2014. Oil production grew 28% in 2015 and represented 66% of total 2015 production, on a BOE basis, in this asset. Horizontal production surpassed vertical production in the third quarter of 2015 and represented approximately 50% of total production for the year. Production for 2015 was negatively impacted by approximately 4 MBOEPD related to the Company’s continuing decision to reject ethane due to weak market conditions.
Spraberry/Wolfcamp area production is expected to grow by 30%+ in 2016, compared to 2015. Production is expected to increase sequentially throughout the year. During the first quarter, the Company expects to place approximately 45 horizontal wells on production in the Spraberry/Wolfcamp, similar to the fourth quarter of 2015. However, first quarter production is expected to be negatively impacted by shut-in production associated with offset fracture stimulations being approximately three times greater than the fourth quarter, as most of the wells being placed on production in the first quarter will be near existing pads where wells are already producing. The existing nearby wells must be shut in while the new wells are being fracture stimulated to avoid damaging them.
Spraberry/Wolfcamp Infrastructure Plans
Pioneer is focused on optimizing the development of the Spraberry/Wolfcamp, which includes ensuring that future infrastructure requirements are constructed. These requirements include the build-out of horizontal tank batteries and saltwater disposal facilities, construction of a field-wide water distribution system, construction of additional gas processing facilities and the expansion of the sand mine in Brady, Texas. In response to the outlook for continuing weak oil prices, the Company has minimized its infrastructure spending in 2016.
Forecasted spending for the construction of tank batteries and saltwater disposal facilities reflects a combination of building new facilities and expanding existing facilities. The Company expects to spend approximately $170 million in 2016 for horizontal tank batteries and saltwater disposal facilities in the northern Spraberry/Wolfcamp and the southern Wolfcamp joint venture areas. This amount is net of the carry that Pioneer currently receives from Sinochem in the southern Wolfcamp joint venture area. The cost to connect an individual well is expected to decline from approximately $900 thousand per well in 2015 to $750 thousand per well in 2016 as the benefits of centralized facilities continue to be realized.
Pioneer owns a 27% interest in Targa Resources’ (“Targa”) West Texas gas processing system and a 30% interest in WTG’s Sale Ranch gas processing system. These investments (i) improve Pioneer’s contract terms for field gas processing, (ii) ensure the timely connection of Pioneer’s new horizontal wells and (iii) provide the Company with opportunities to benefit from third-party processing revenues. During 2016, the Company expects to spend approximately $45 million on gas processing system additions, including $35 million for gathering system compression and new connections and $10 million to complete Targa’s new 200 million cubic feet per day (MMCFPD) gas processing plant in Martin County (Buffalo plant), which is expected to be placed into service during the second quarter of 2016. No new plants are expected to be required after the Buffalo plant is completed until there is a significant increase in the Midland Basin rig count.
The Company’s long-term plans call for the construction of a field-wide water distribution system to reduce the cost of water for drilling and completion activities and to ensure that adequate supplies of non-potable water are available for use in the development of the Spraberry/Wolfcamp field. The system is expected to be built out based on the timing of adding new rigs and the economics associated with adding new water sources. The Company recently completed construction of a delivery line for 391 million barrels of effluent water that will be purchased from the city of Odessa over the next 11 years. The 2016 budget includes $45 million for expansion of the mainline system, subsystems and frac ponds to efficiently deliver the water from Odessa to Pioneer drilling locations at an expected savings of approximately $100 thousand per well. The Company continues to pursue a long-term agreement to purchase effluent water from the city of Midland.
Pioneer’s sand mine in Brady, Texas, which is strategically located within close proximity (~190 miles) of the Spraberry/Wolfcamp field, provides a low-cost sand source for the Company’s horizontal drilling program. Engineering work and site preparation for the expansion of the mine from 750 thousand tons to 2.1 million tons were completed during 2015. The timing for completing the expansion will depend on the timing of future horizontal rig additions by Pioneer.
2016 Capital Program
The Company’s capital budget for 2016 is $2.0 billion (excluding acquisitions, asset retirement obligations, capitalized interest and geological and geophysical G&A), down from the preliminary forecast of $2.4 billion to $2.6 billion and 2015 actual spending of $2.2 billion. The budget includes $1.85 billion for drilling-and-completions-related activities, including tank batteries/saltwater disposal facilities and gas processing facilities, and $150 million for water infrastructure, vertical integration, systems upgrades and field facilities.
The following provides a breakdown of the capital budget by asset:
- Northern Spraberry/Wolfcamp – $1,710 million (includes $1,440 million for the horizontal drilling program, $160 million for tank batteries/saltwater disposal facilities, $45 million for gas processing facilities and $65 million for land/science/other);
- Southern Wolfcamp joint venture area (net of carry) – $60 million (includes $45 million for the horizontal drilling program, $10 million for tank batteries/saltwater disposal facilities and $5 million for land/other);
- Eagle Ford Shale – $60 million (includes $30 million for the horizontal drilling program and $30 million for compression, land and other); and
- Other assets – $20 million.
The 2016 capital budget is expected to be funded from forecasted operating cash flow of $1.3 billion (assuming average 2016 estimated prices of $36.00 per barrel for oil and $2.35 per thousand cubic feet (MCF) for gas), cash on hand (excludes proceeds from Pioneer’s December 2015 notes offering) and the remaining $500 million of proceeds from the Eagle Ford Shale midstream business sale that will be received in July 2016.
The Company expects to deliver production growth of 10%+ in 2016 compared to 2015 based on the above capital program. This growth reflects Spraberry/Wolfcamp area production growing by 30%+, partially offset by declines of approximately 25% in the Eagle Ford Shale and 10% across Pioneer’s other assets.
Fourth Quarter 2015 Financial Review
Sales volumes for the fourth quarter of 2015 averaged 215 MBOEPD. Oil sales averaged 113 thousand barrels per day (MBPD), NGL sales averaged 41 MBPD and gas sales averaged 367 MMCFPD.
The average realized price for oil was $37.92 per barrel. The average realized price for NGLs was $12.16 per barrel, and the average realized price for gas was $2.03 per MCF. These prices exclude the effects of derivatives.
Production costs averaged $11.02 per BOE. Depreciation, depletion and amortization (DD&A) expense averaged $19.35 per BOE. Exploration and abandonment costs were $21 million, principally comprised of $5 million attributable to drilling, acreage and other abandonments, $1 million for seismic data and $15 million for personnel costs. General and administrative expense totaled $81 million. Interest expense was $48 million, and other expense was $129 million, including (i) $64 million of other noncash impairments, principally excess vertical pipe inventory, (ii) stacked drilling rig charges of $18 million, (iii) $17 million of losses (principally noncash) associated with the portion of vertical integration services provided to nonaffiliated working interest owners, including joint venture partners, in wells operated by the Company and (iv) $14 million of charges associated with excess firm gathering and transportation commitments. A current income tax benefit of $26 million was recognized in the fourth quarter as a result of a change in the bonus depreciation laws in December, which reduced estimated 2015 alternative minimum tax obligations by $42 million.
First Quarter 2016 Financial Outlook
The Company’s first quarter 2016 outlook for certain operating and financial items is provided below.
Production is forecasted to average 211 MBOEPD to 216 MBOEPD.
Production costs are expected to average $10.50 per BOE to $12.50 per BOE. DD&A expense is expected to average $18.50 per BOE to $20.50 per BOE. Total exploration and abandonment expense is forecasted to be $20 million to $30 million.
General and administrative expense is expected to be $78 million to $83 million, interest expense is expected to be $58 million to $63 million and other expense is expected to be $70 million to $80 million. Other expense includes $20 million to $25 million of expected charges for each of the following: (i) stacked drilling rig charges, (ii) charges associated with excess firm gathering and transportation commitments and (iii) estimated losses (principally noncash) associated with the portion of vertical integration services provided to nonaffiliated working interest owners, including joint venture partners, in wells operated by the Company. Accretion of discount on asset retirement obligations is expected to be $3 million to $5 million.
Pioneer expects to incur restructuring charges of $10 million to $20 million when it reports earnings for the first quarter of 2016 as a result of relocating its two pressure pumping fleets from the Eagle Ford Shale to the Spraberry/Wolfcamp. The restructuring charges include relocation and severance payments and other related costs.
The Company’s effective income tax rate is expected to range from 35% to 40%. Current income taxes are expected to be $1 million to $5 million.
The Company’s financial and derivative mark-to-market results and open derivatives positions are outlined on the attached schedules.
Earnings Conference Call
On Thursday, February 11, 2016, at 9:00 a.m. Central Time, Pioneer will discuss its financial and operating results for the quarter ended December 31, 2015, and its 2016 capital program, with an accompanying presentation. Instructions for listening to the call and viewing the accompanying presentation are shown below.
Website: www.pxd.com
Select “Investors,” then “Earnings & Webcasts” to listen to the discussion, view the presentation and see other related material.
Telephone: Dial (877) 675-4750 and confirmation code 6797143 five minutes before the call. View the presentation via Pioneer’s website address above.
A replay of the webcast will be archived on Pioneer’s website. A telephone replay will be available through March 6, 2016, by dialing (888) 203-1112 and confirmation code 6797143.
Pioneer is a large independent oil and gas exploration and production company, headquartered in Dallas, Texas, with operations in the United States. For more information, visit www.pxd.com.
Except for historical information contained herein, the statements in this news release are forward-looking statements that are made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause Pioneer's actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties include, among other things, volatility of commodity prices, product supply and demand, competition, the ability to obtain environmental and other permits and the timing thereof, other government regulation or action, the ability to obtain approvals from third parties and negotiate agreements with third parties on mutually acceptable terms, litigation, the costs and results of drilling and operations, including the ability to realize future reductions in costs, availability of equipment, services, resources and personnel required to perform the Company’s drilling and operating activities, access to and availability of transportation, processing, fractionation and refining facilities, Pioneer's ability to replace reserves, implement its business plans or complete its development activities as scheduled, access to and cost of capital, uncertainties about estimates of reserves and resource potential and the ability to add proved reserves in the future, the assumptions underlying production forecasts, quality of technical data, environmental and weather risks, including the possible impacts of climate change, the risks associated with the ownership and operation of the Company’s industrial sand mining and oilfield services businesses and acts of war or terrorism. These and other risks are described in Pioneer's 10-K and 10-Q Reports and other filings with the U.S. Securities and Exchange Commission (SEC). In addition, Pioneer may be subject to currently unforeseen risks that may have a materially adverse impact on it. Pioneer undertakes no duty to publicly update these statements except as required by law.
Cautionary Note to U.S. Investors --The SEC prohibits oil and gas companies, in their filings with the SEC, from disclosing estimates of oil or gas resources other than “reserves,” as that term is defined by the SEC. In this news release, Pioneer includes estimates of quantities of oil and gas using certain terms, such as “resource potential,” “net recoverable resource potential,” “estimated ultimate recovery,” “EUR,” “oil-in-place” or other descriptions of volumes of reserves, which terms include quantities of oil and gas that may not meet the SEC’s definitions of proved, probable and possible reserves, and which the SEC's guidelines strictly prohibit Pioneer from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being recovered by Pioneer.
An audit of proved reserves follows the general principles set forth in the standards pertaining to the estimating and auditing of oil and gas reserve information promulgated by the Society of Petroleum Engineers (“SPE”). A reserve audit as defined by the SPE is not the same as a financial audit. Please see the Company's Annual Report on Form 10-K for a general description of the concepts included in the SPE's definition of a reserve audit.
“Drillbit finding and development cost per BOE,” or “drillbit F&D cost per BOE,” means the summation of exploration and development costs incurred divided by the summation of annual proved reserves, on a BOE basis, attributable to discoveries and extensions (excludes purchases of minerals-in-place) and revisions of previous estimates. Revisions of previous estimates exclude price revisions. Consistent with industry practice, future capital costs to develop proved undeveloped reserves are not included in costs incurred.
“Drillbit reserve replacement” is the summation of annual proved reserves, on a BOE basis, attributable to discoveries and extensions (excludes purchases of minerals-in-place) and revisions of previous estimates divided by annual production of oil, NGLs and gas, on a BOE basis. Revisions of previous estimates exclude price revisions.
U.S. investors are urged to consider closely the disclosures in the Company’s periodic filings with the SEC. Such filings are available from the Company at 5205 N. O'Connor Blvd., Suite 200, Irving, Texas 75039, Attention: Investor Relations, and the Company’s website at www.pxd.com. These filings also can be obtained from the SEC by calling 1-800-SEC-0330.
| PIONEER NATURAL RESOURCES COMPANY | ||||||||||
| UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS | ||||||||||
| (in millions) | ||||||||||
|
December 31, |
December 31, |
|||||||||
| ASSETS | ||||||||||
| Current assets: | ||||||||||
| Cash and cash equivalents | $ | 1,391 | $ | 1,025 | ||||||
| Accounts receivable, net | 385 | 440 | ||||||||
| Income taxes receivable | 43 | 23 | ||||||||
| Inventories | 155 | 241 | ||||||||
| Prepaid expenses | 17 | 15 | ||||||||
| Notes receivable | 498 | — | ||||||||
| Derivatives | 694 | 578 | ||||||||
| Other | 11 | 37 | ||||||||
| Total current assets | 3,194 | 2,359 | ||||||||
| Property, plant and equipment, at cost: | ||||||||||
| Oil and gas properties, using the successful efforts method of accounting | 16,800 | 15,821 | ||||||||
| Accumulated depletion, depreciation and amortization | (6,778 | ) | (5,431 | ) | ||||||
| Total property, plant and equipment | 10,022 | 10,390 | ||||||||
| Goodwill | 272 | 272 | ||||||||
| Other property and equipment, net | 1,523 | 1,391 | ||||||||
| Investment in unconsolidated affiliate | — | 239 | ||||||||
| Derivatives | 64 | 181 | ||||||||
| Other assets, net | 79 | 77 | ||||||||
| $ | 15,154 | $ | 14,909 | |||||||
| LIABILITIES AND EQUITY | ||||||||||
| Current liabilities: | ||||||||||
| Accounts payable | $ | 883 | $ | 1,320 | ||||||
| Interest payable | 65 | 40 | ||||||||
| Income taxes payable | 2 | 1 | ||||||||
| Current portion of long-term debt | 448 | — | ||||||||
| Derivatives | — | 3 | ||||||||
| Other | 64 | 55 | ||||||||
| Total current liabilities | 1,462 | 1,419 | ||||||||
| Long-term debt | 3,207 | 2,648 | ||||||||
| Derivatives | 1 | 2 | ||||||||
| Deferred income taxes | 1,776 | 1,964 | ||||||||
| Other liabilities | 333 | 287 | ||||||||
| Equity | 8,375 | 8,589 | ||||||||
| $ | 15,154 | $ | 14,909 | |||||||
| PIONEER NATURAL RESOURCES COMPANY | ||||||||||||||||||
| UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS | ||||||||||||||||||
| (in millions, except per share data) | ||||||||||||||||||
|
Three Months Ended |
Twelve Months Ended |
|||||||||||||||||
| 2015 | 2014 | 2015 | 2014 | |||||||||||||||
| Revenues and other income: | ||||||||||||||||||
| Oil and gas | $ | 508 | $ | 804 | $ | 2,178 | $ | 3,599 | ||||||||||
| Sales of purchased oil and gas | 299 | 172 | 964 | 726 | ||||||||||||||
| Interest and other | 5 | 7 | 22 | 26 | ||||||||||||||
| Derivative gains, net | 262 | 693 | 879 | 712 | ||||||||||||||
| Gain (loss) on disposition of assets, net | — | (2 | ) | 782 | 9 | |||||||||||||
| 1,074 | 1,674 | 4,825 | 5,072 | |||||||||||||||
| Costs and expenses: | ||||||||||||||||||
| Oil and gas production | 185 | 200 | 717 | 693 | ||||||||||||||
| Production and ad valorem taxes | 33 | 51 | 145 | 220 | ||||||||||||||
| Depletion, depreciation and amortization | 382 | 313 | 1,385 | 1,047 | ||||||||||||||
| Purchased oil and gas | 319 | 168 | 1,003 | 703 | ||||||||||||||
| Impairment of oil and gas properties | 846 | — | 1,056 | — | ||||||||||||||
| Exploration and abandonments | 21 | 97 | 99 | 177 | ||||||||||||||
| General and administrative | 81 | 89 | 327 | 333 | ||||||||||||||
| Accretion of discount on asset retirement obligations | 3 | 3 | 12 | 12 | ||||||||||||||
| Interest | 48 | 46 | 187 | 184 | ||||||||||||||
| Other | 129 | 41 | 315 | 106 | ||||||||||||||
| 2,047 | 1,008 | 5,246 | 3,475 | |||||||||||||||
| Income (loss) from continuing operations before income taxes | (973 | ) | 666 | (421 | ) | 1,597 | ||||||||||||
| Income tax benefit (provision) | 351 | (237 | ) | 155 | (556 | ) | ||||||||||||
| Income (loss) from continuing operations | (622 | ) | 429 | (266 | ) | 1,041 | ||||||||||||
| Income (loss) from discontinued operations, net of tax | (1 | ) | 2 | (7 | ) | (111 | ) | |||||||||||
| Net income (loss) attributable to common stockholders | $ | (623 | ) | $ | 431 | $ | (273 | ) | $ | 930 | ||||||||
| Basic earnings per share attributable to common stockholders: | ||||||||||||||||||
| Income (loss) from continuing operations | $ | (4.17 | ) | $ | 2.91 | $ | (1.79 | ) | $ | 7.17 | ||||||||
| Income (loss) from discontinued operations | — | 0.01 | (0.04 | ) | (0.77 | ) | ||||||||||||
| Net income (loss) | $ | (4.17 | ) | $ | 2.92 | $ | (1.83 | ) | $ | 6.40 | ||||||||
| Diluted earnings per share attributable to common stockholders: | ||||||||||||||||||
| Income (loss) from continuing operations | $ | (4.17 | ) | $ | 2.90 | $ | (1.79 | ) | $ | 7.15 | ||||||||
| Income (loss) from discontinued operations | — | 0.01 | (0.04 | ) | (0.77 | ) | ||||||||||||
| Net income (loss) | $ | (4.17 | ) | $ | 2.91 | $ | (1.83 | ) | $ | 6.38 | ||||||||
| Weighted average shares outstanding: | ||||||||||||||||||
| Basic | 149 | 146 | 149 | 144 | ||||||||||||||
| Diluted | 149 | 147 | 149 | 144 | ||||||||||||||
| PIONEER NATURAL RESOURCES COMPANY | ||||||||||||||||||
| UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | ||||||||||||||||||
| (in millions) | ||||||||||||||||||
|
Three Months Ended |
Twelve Months Ended |
|||||||||||||||||
| 2015 | 2014 | 2015 | 2014 | |||||||||||||||
| Cash flows from operating activities: | ||||||||||||||||||
| Net income (loss) | $ | (623 | ) | $ | 431 | $ | (273 | ) | $ | 930 | ||||||||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||||||||
| Depletion, depreciation and amortization | 382 | 313 | 1,385 | 1,047 | ||||||||||||||
| Impairment of oil and gas properties | 846 | — | 1,056 | — | ||||||||||||||
| Impairment of inventory and other property and equipment | 64 | 1 | 86 | 8 | ||||||||||||||
| Exploration expenses, including dry holes | 6 | 79 | 28 | 90 | ||||||||||||||
| Deferred income taxes | (325 | ) | 237 | (178 | ) | 552 | ||||||||||||
| (Gain) loss on disposition of assets, net | — | 2 | (782 | ) | (9 | ) | ||||||||||||
| Accretion of discount on asset retirement obligations | 3 | 3 | 12 | 12 | ||||||||||||||
| Discontinued operations | — | 4 | (4 | ) | 251 | |||||||||||||
| Interest expense | 4 | 4 | 18 | 17 | ||||||||||||||
| Derivative related activity | 20 | (570 | ) | (3 | ) | (609 | ) | |||||||||||
| Amortization of stock-based compensation | 21 | 21 | 90 | 84 | ||||||||||||||
| Other noncash items | 25 | (9 | ) | 38 | 34 | |||||||||||||
| Change in operating assets and liabilities: | ||||||||||||||||||
| Accounts receivable, net | 29 | 48 | 54 | (29 | ) | |||||||||||||
| Income taxes receivable | (43 | ) | (1 | ) | (20 | ) | (18 | ) | ||||||||||
| Inventories | 37 | (10 | ) | 8 | (37 | ) | ||||||||||||
| Prepaid expenses | 1 | 8 | (2 | ) | (3 | ) | ||||||||||||
| Other current assets | 8 | 2 | 2 | 1 | ||||||||||||||
| Accounts payable | 8 | 8 | (258 | ) | 104 | |||||||||||||
| Interest payable | 29 | 4 | 25 | (22 | ) | |||||||||||||
| Income taxes payable | (24 | ) | — | 1 | 1 | |||||||||||||
| Other current liabilities | (7 | ) | (8 | ) | (35 | ) | (38 | ) | ||||||||||
| Net cash provided by operating activities | 461 | 567 | 1,248 | 2,366 | ||||||||||||||
| Net cash used in investing activities | (633 | ) | (1,070 | ) | (1,840 | ) | (2,699 | ) | ||||||||||
| Net cash provided by financing activities | 982 | 978 | 958 | 965 | ||||||||||||||
| Net increase in cash and cash equivalents | 810 | 475 | 366 | 632 | ||||||||||||||
| Cash and cash equivalents, beginning of period | 581 | 550 | 1,025 | 393 | ||||||||||||||
| Cash and cash equivalents, end of period | $ | 1,391 | $ | 1,025 | $ | 1,391 | $ | 1,025 | ||||||||||
| PIONEER NATURAL RESOURCES COMPANY | |||||||||||||||||
| UNAUDITED SUMMARY PRODUCTION AND PRICE DATA | |||||||||||||||||
|
Three Months Ended |
Twelve Months Ended |
||||||||||||||||
| 2015 | 2014 | 2015 | 2014 | ||||||||||||||
| Average Daily Sales Volumes: | |||||||||||||||||
| Oil (Bbls) | 112,965 | 100,532 | 105,347 | 87,034 | |||||||||||||
| Natural gas liquids ("NGL") (Bbls) | 40,639 | 42,582 | 38,592 | 38,646 | |||||||||||||
| Gas (Mcf) | 366,799 | 347,035 | 360,662 | 339,341 | |||||||||||||
| Total (BOE) | 214,738 | 200,953 | 204,050 | 182,237 | |||||||||||||
| Average Prices: | |||||||||||||||||
| Oil (per Bbl) | $ | 37.92 | $ | 66.64 | $ | 43.55 | $ | 85.29 | |||||||||
| NGL (per Bbl) | $ | 12.16 | $ | 18.50 | $ | 13.31 | $ | 27.06 | |||||||||
| Gas (per Mcf) | $ | 2.03 | $ | 3.60 | $ | 2.40 | $ | 4.10 | |||||||||
| Total (BOE) | $ | 25.72 | $ | 43.48 | $ | 29.25 | $ | 54.11 | |||||||||
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY EARNINGS PER SHARE INFORMATION
The Company uses the two-class method of calculating basic and diluted earnings per share. Under the two-class method of calculating earnings per share, generally acceptable accounting principles ("GAAP") provide that share-based awards with guaranteed dividend or distribution participation rights qualify as "participating securities" during their vesting periods. The Company's basic net income (loss) per share attributable to common stockholders is computed as (i) net income (loss) attributable to common stockholders, (ii) less participating share-based basic earnings (iii) divided by weighted average basic shares outstanding. The Company's diluted net income (loss) per share attributable to common stockholders is computed as (i) basic net income (loss) attributable to common stockholders, (ii) plus the reallocation of participating earnings, if any, (iii) divided by weighted average diluted shares outstanding. During periods in which the Company realizes a loss from continuing operations attributable to common stockholders, securities or other contracts to issue common stock would be dilutive to loss per share; therefore, conversion into common stock is assumed not to occur.
The following table is a reconciliation of the Company's net income (loss) attributable to common stockholders to basic and diluted net income (loss) attributable to common stockholders for the three and twelve months ended December 31, 2015 and 2014:
|
Three Months Ended |
Twelve Months Ended |
|||||||||||||||||
| 2015 | 2014 | 2015 | 2014 | |||||||||||||||
| (in millions) | ||||||||||||||||||
| Net income (loss) attributable to common stockholders | $ | (623 | ) | $ | 431 | $ | (273 | ) | $ | 930 | ||||||||
| Participating basic earnings | — | (5 | ) | — | (10 | ) | ||||||||||||
| Basic and diluted net income (loss) attributable to common stockholders | $ | (623 | ) | $ | 426 | $ | (273 | ) | $ | 920 | ||||||||
Basic and diluted weighted average common shares outstanding were 149 million for both the three and twelve months ended December 31, 2015. Basic and diluted weighted average common shares outstanding were 146 million and 147 million for the three months ended December 31, 2014, respectively. Basic and diluted weighted average common shares outstanding were 144 million for the twelve months ended December 31, 2014.
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES
(in
millions)
EBITDAX and discretionary cash flow ("DCF") (as defined below) are presented herein, and reconciled to the GAAP measures of net income (loss) and net cash provided by operating activities, because of their wide acceptance by the investment community as financial indicators of a company's ability to internally fund exploration and development activities and to service or incur debt. The Company also views the non-GAAP measures of EBITDAX and DCF as useful tools for comparisons of the Company's financial indicators with those of peer companies that follow the full cost method of accounting. EBITDAX and DCF should not be considered as alternatives to net income (loss) or net cash provided by operating activities, as defined by GAAP.
|
Three Months Ended |
Twelve Months Ended |
|||||||||||||||||
| 2015 | 2014 | 2015 | 2014 | |||||||||||||||
| Net income (loss) | $ | (623 | ) | $ | 431 | $ | (273 | ) | $ | 930 | ||||||||
| Depletion, depreciation and amortization | 382 | 313 | 1,385 | 1,047 | ||||||||||||||
| Exploration and abandonments | 21 | 97 | 99 | 177 | ||||||||||||||
| Impairment of oil and gas properties | 846 | — | 1,056 | — | ||||||||||||||
| Impairment of inventory and other property and equipment | 64 | 1 | 86 | 8 | ||||||||||||||
| Accretion of discount on asset retirement obligations | 3 | 3 | 12 | 12 | ||||||||||||||
| Interest expense | 48 | 46 | 187 | 184 | ||||||||||||||
| Income tax (benefit) provision | (351 | ) | 237 | (155 | ) | 556 | ||||||||||||
| (Gain) loss on disposition of assets, net | — | 2 | (782 | ) | (9 | ) | ||||||||||||
| (Income) loss from discontinued operations, net of tax | 1 | (2 | ) | 7 | 111 | |||||||||||||
| Derivative related activity | 20 | (570 | ) | (3 | ) | (609 | ) | |||||||||||
| Amortization of stock-based compensation | 21 | 21 | 90 | 84 | ||||||||||||||
| Other | 25 | (9 | ) | 38 | 34 | |||||||||||||
| EBITDAX (a) | 457 | 570 | 1,747 | 2,525 | ||||||||||||||
| Cash interest expense | (44 | ) | (42 | ) | (169 | ) | (167 | ) | ||||||||||
| Current income tax benefit (provision) | 26 | — | (23 | ) | (4 | ) | ||||||||||||
| Discretionary cash flow (b) | 439 | 528 | 1,555 | 2,354 | ||||||||||||||
| Discontinued operations cash activity | (1 | ) | 6 | (11 | ) | 140 | ||||||||||||
| Cash exploration expense | (15 | ) | (18 | ) | (71 | ) | (87 | ) | ||||||||||
| Changes in operating assets and liabilities | 38 | 51 | (225 | ) | (41 | ) | ||||||||||||
| Net cash provided by operating activities | $ | 461 | $ | 567 | $ | 1,248 | $ | 2,366 | ||||||||||
_______________
| (a) | “EBITDAX” represents earnings before depletion, depreciation and amortization expense; exploration and abandonments; impairment of oil and gas properties; impairment of inventory and other property and equipment; accretion of discount on asset retirement obligations; interest expense; income taxes; net (gain) loss on the disposition of assets; (income) loss from discontinued operations, net of tax; noncash derivative related activity; amortization of stock-based compensation and other items. | ||
| (b) | Discretionary cash flow equals cash flows from operating activities before changes in operating assets and liabilities and cash activity reflected in discontinued operations and exploration expense. | ||
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES (continued)
(in
millions, except per share data)
Net loss adjusted for noncash mark-to-market ("MTM") derivative losses, and adjusted loss excluding noncash MTM derivative losses and unusual items, as presented in this press release, are presented and reconciled to Pioneer's net loss attributable to common stockholders (determined in accordance with GAAP) because Pioneer believes that these non-GAAP financial measures reflect an additional way of viewing aspects of Pioneer's business that, when viewed together with its financial results computed in accordance with GAAP, provides a more complete understanding of factors and trends affecting its historical financial performance and future operating results, greater transparency of underlying trends and greater comparability of results across periods. In addition, management believes that these non-GAAP measures may enhance investors' ability to assess Pioneer's historical and future financial performance. These non-GAAP financial measures are not intended to be substitutes for the comparable GAAP measure and should be read only in conjunction with Pioneer's consolidated financial statements prepared in accordance with GAAP. Noncash MTM derivative gains and losses and unusual items will recur in future periods; however, the amount and frequency can vary significantly from period to period. The table below reconciles Pioneer's net loss attributable to common stockholders for the three months ended December 31, 2015, as determined in accordance with GAAP, to adjusted loss excluding noncash MTM derivative losses and adjusted loss excluding noncash MTM derivative losses and unusual items for that quarter.
|
After-tax |
Amounts |
|||||||||
| Net loss attributable to common stockholders | $ | (623 | ) | $ | (4.17 | ) | ||||
| Noncash MTM derivative losses | 13 | 0.09 | ||||||||
| Adjusted loss excluding noncash MTM derivative losses | (610 | ) | (4.08 | ) | ||||||
| Eagle Ford Shale proved properties noncash impairment | 542 | 3.63 | ||||||||
| Other noncash impairments, principally excess vertical pipe inventory | 41 | 0.27 | ||||||||
| Adjusted loss excluding noncash MTM derivative losses and unusual items | $ | (27 | ) | $ | (0.18 | ) | ||||
| PIONEER NATURAL RESOURCES COMPANY | |||||||||||||||||||||||||
| SUPPLEMENTAL INFORMATION | |||||||||||||||||||||||||
| Open Commodity Derivative Positions as of February 9, 2016 | |||||||||||||||||||||||||
| (Volumes are average daily amounts) | |||||||||||||||||||||||||
| 2016 |
Twelve Months |
||||||||||||||||||||||||
|
First |
Second |
Third |
Fourth |
2017 | |||||||||||||||||||||
| Average Daily Oil Production Associated with Derivatives (Bbl): | |||||||||||||||||||||||||
| Swap contracts: | |||||||||||||||||||||||||
| Volume | 35,000 | 35,000 | — | — | — | ||||||||||||||||||||
| NYMEX price | $ | 59.88 | $ | 59.88 | $ | — | $ | — | $ | — | |||||||||||||||
| Collar contracts with short puts: | |||||||||||||||||||||||||
| Volume | 63,000 | 68,000 | 112,000 | 112,000 | 34,000 | ||||||||||||||||||||
| NYMEX price: | |||||||||||||||||||||||||
| Ceiling | $ | 73.29 | $ | 72.43 | $ | 75.94 | $ | 75.94 | $ | 70.42 | |||||||||||||||
| Floor | $ | 63.04 | $ | 62.08 | $ | 65.41 | $ | 65.41 | $ | 57.65 | |||||||||||||||
| Short put | $ | 43.17 | $ | 42.94 | $ | 47.03 | $ | 47.03 | $ | 47.65 | |||||||||||||||
| Average Daily NGL Production Associated with Derivatives (Bbl): | |||||||||||||||||||||||||
| Propane Swap contracts (a): | |||||||||||||||||||||||||
| Volume | 7,500 | 7,500 | 7,500 | 7,500 | — | ||||||||||||||||||||
| Index price | $ | 21.57 | $ | 21.57 | $ | 21.57 | $ | 21.57 | $ | — | |||||||||||||||
| Average Daily Gas Production Associated with Derivatives (MMBtu): | |||||||||||||||||||||||||
| Swap contracts: | |||||||||||||||||||||||||
| Volume | 70,000 | 70,000 | 70,000 | 70,000 | — | ||||||||||||||||||||
| NYMEX price | $ | 4.06 | $ | 4.06 | $ | 4.06 | $ | 4.06 | $ | — | |||||||||||||||
| Collar contracts with short puts: | |||||||||||||||||||||||||
| Volume | 180,000 | 180,000 | 180,000 | 180,000 | — | ||||||||||||||||||||
| NYMEX price: | |||||||||||||||||||||||||
| Ceiling | $ | 4.01 | $ | 4.01 | $ | 4.01 | $ | 4.01 | $ | — | |||||||||||||||
| Floor | $ | 3.24 | $ | 3.24 | $ | 3.24 | $ | 3.24 | $ | — | |||||||||||||||
| Short put | $ | 2.78 | $ | 2.78 | $ | 2.78 | $ | 2.78 | $ | — | |||||||||||||||
| Basis swap contracts: | |||||||||||||||||||||||||
| Gulf Coast index swap volume (b) | 10,000 | 10,000 | 10,000 | 10,000 | — | ||||||||||||||||||||
| Price differential ($/MMBtu) | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||||||||
| Mid-Continent index swap volume (b) | 15,000 | 15,000 | 15,000 | 15,000 | 45,000 | ||||||||||||||||||||
| Price differential ($/MMBtu) | $ | (0.32 | ) | $ | (0.32 | ) | $ | (0.32 | ) | $ | (0.32 | ) | $ | (0.32 | ) | ||||||||||
| Permian Basin index swap volume (c) | 6,813 | — | — | 34,946 | 9,863 | ||||||||||||||||||||
| Price differential ($/MMBtu) | $ | 0.26 | $ | — | $ | — | $ | 0.41 | $ | 0.37 | |||||||||||||||
_______________
| (a) | Represent swap contracts that reduce the price volatility of forecasted propane sales by the Company at Mont Belvieu, Texas and Conway, Kansas-posted prices. | ||
| (b) | Represent swaps that fix the basis differentials between the index prices at which the Company sells its Gulf Coast and Mid-Continent gas, respectively, and the NYMEX Henry Hub index price used in gas swap and collar contracts with short puts. | ||
| (c) | Represent swaps 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. | ||
Interest rate derivatives. As of December 31, 2015, the Company did not have any interest rate derivatives outstanding. Subsequent to December 31, 2015, the Company entered into 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 an average fixed rate of 2.03 percent on a notional amount of $150 million on December 15, 2017.
Marketing and basis derivative activities. Periodically, the Company enters into buy and sell marketing arrangements to fulfill firm pipeline transportation commitments. Associated with these marketing arrangements, the Company may enter into index swaps to mitigate price risk. As of December 31, 2015 and February 9, 2016, the Company did not have any marketing derivatives outstanding.
| Derivative Gains, Net | ||||||||||
| (in millions) | ||||||||||
|
Three Months Ended |
Twelve Months Ended |
|||||||||
| Noncash changes in fair value: | ||||||||||
| Oil derivative gains (losses) | $ | (10 | ) | $ | 36 | |||||
| NGL derivative gains | — | 8 | ||||||||
| Gas derivative losses | (12 | ) | (41 | ) | ||||||
| Marketing derivative losses | — | (3 | ) | |||||||
| Interest rate derivative gains | 2 | 3 | ||||||||
| Total noncash derivative gains (losses), net | (20 | ) | 3 | |||||||
| Net cash receipts (payments) on settled derivative instruments: | ||||||||||
| Oil derivative receipts | 240 | 744 | ||||||||
| NGL derivative receipts | 11 | 18 | ||||||||
| Gas derivative receipts | 29 | 114 | ||||||||
| Marketing derivative receipts (payments) | 1 | (3 | ) | |||||||
| Interest rate derivative receipts | 1 | 3 | ||||||||
| Total cash receipts on settled derivative instruments, net | 282 | 876 | ||||||||
| Total derivative gains, net | $ | 262 | $ | 879 | ||||||