DALLAS--(BUSINESS WIRE)--Pioneer Natural Resources Company (NYSE:PXD) (“Pioneer” or “the Company”) today announced financial and operating results for the quarter ended June 30, 2013.
Pioneer reported second quarter net income attributable to common stockholders of $337 million, or $2.40 per diluted share (see attached schedule for a description of the net income per diluted share calculation). Without the effect of noncash derivative mark-to-market gains and other unusual items, adjusted income for the second quarter was $154 million after tax, or $1.10 per diluted share.
Second quarter and other recent highlights included:
- producing 176.2 thousand barrels oil equivalent per day (MBOEPD) in the second quarter, an increase from the first quarter of 2013 of 5 MBOEPD, or 3%, as a result of continued production growth from the Company’s drilling programs in the liquids-rich horizontal Spraberry/Wolfcamp and Eagle Ford Shale areas; production would have been 177.6 MBOEPD excluding the effects of unexpected ethane rejection of 1.4 MBOEPD in the Spraberry/Wolfcamp area;
- narrowing the full-year 2013 production growth guidance range to 14% to 16% from 12% to 16%;
- progressing the highly successful northern horizontal Spraberry/Wolfcamp drilling program by placing on production (i) Pioneer’s first Wolfcamp A interval well in Midland County with a peak 24-hour initial production rate of 1,712 barrels oil equivalent per day (BOEPD), a peak 30-day average production rate of 1,107 BOEPD and an oil content of 74% and (ii) Pioneer’s first Wolfcamp B interval well in Martin County with a peak 24-hour initial production rate of 1,572 BOEPD, a peak 30-day average production rate of 1,040 BOEPD and an oil content of 76%;
- announcing that Pioneer’s first Wolfcamp B interval well in Midland County achieved cumulative production of 140 thousand barrels oil equivalent (MBOE) in six months;
- increasing from one horizontal rig to five horizontal rigs in the northern Spraberry/Wolfcamp area during the second quarter, with three rigs currently drilling Wolfcamp B and D interval wells in Midland and Martin counties and two rigs currently drilling Jo Mill and Lower Spraberry interval wells in Midland and Martin counties; planning to move two of the five rigs during the third quarter to drill the Company’s first horizontal Wolfcamp and Spraberry Shale wells in Andrews County;
- closing the southern Wolfcamp joint venture transaction with Sinochem Petroleum USA LLC, a U.S. subsidiary of the Sinochem Group (“Sinochem”) on May 31 (June 2013 production was lower by approximately 4,000 BOEPD, or approximately 1,300 BOEPD for the second quarter, reflecting Sinochem’s 40% share of production after closing);
- placing 22 new Wolfcamp B interval wells in the southern Wolfcamp joint venture area on production during the second quarter with peak 24-hour initial production rates up to approximately 1,000 BOEPD; well results continue to meet expectations;
- delivering development well costs ranging from $7.5 million to $8.0 million for 8,300-foot lateral wells in the southern Wolfcamp joint venture area; includes the benefits of lower slickwater fracture stimulation costs and declining hybrid fracture stimulation costs;
- adding oil derivative positions for the 2014 through 2016 period that increased the Company’s oil production coverage levels to approximately 85% in 2014, 60% in 2015 and 15% in 2016; and
- decreasing Pioneer’s net debt-to-book capitalization from 26% at the end of the first quarter to 22% at the end of the second quarter.
Scott Sheffield, Chairman and CEO, stated, “Pioneer delivered another solid quarter with strong earnings and production growth. The Company’s horizontal drilling programs continue to provide significant growth in our liquids-rich Spraberry/Wolfcamp Shale and Eagle Ford Shale plays. As a result, we are narrowing our 2013 production growth forecast to 14% to 16% from a range of 12% to 16%. The new production growth range also reflects that production during the second half of 2013 is expected to be negatively impacted by ongoing ethane rejection due to low ethane prices.”
“We are particularly excited about our continued successful drilling program in the northern horizontal Spraberry/Wolfcamp Shale play, which is validating our extensive Midland Basin geologic mapping. We look forward to the results from our recent ramp up in drilling activity to further delineate the Wolfcamp, Jo Mill and Spraberry Shale intervals in Midland, Martin and Andrews counties.”
Mark-To-Market Derivative Gains and Unusual Items Included in Second Quarter 2013 Earnings
Pioneer’s second quarter earnings included unrealized mark-to-market gains on derivatives of $66 million after tax, or $0.47 per diluted share.
Second quarter earnings also included income of $117 million after tax, or $0.83 per diluted share, related to the following unusual items:
- net gains on the sale of properties, principally associated with the southern Wolfcamp joint venture transaction, of $113 million after tax, or $0.80 per diluted share and
- Alaska production tax credit recoveries of $4 million after tax, or $0.03 per diluted share.
Operations Update and Drilling Program
Pioneer’s successful horizontal Wolfcamp Shale and Jo Mill drilling results in the Spraberry Trend Area field have led the Company to shift a significant portion of its 2013 drilling activity from vertical drilling to more capital-efficient horizontal drilling. Pioneer is the largest acreage holder in the Spraberry Trend Area field, where the Company believes it has greater than 4.6 billion barrels oil equivalent of estimated resource potential from horizontal drilling based on its extensive geologic data and its successful drilling results to date.
Pioneer is in the midst of a horizontal drilling program in 2013 and 2014 to appraise the Company’s northern Spraberry/Wolfcamp acreage. The Company plans to invest $400 million during 2013 to drill a total of 30 to 40 wells targeting six different “stacked” intervals across its northern acreage. The six “stacked” intervals across the Company’s 600,000 prospective gross acres in the north equate to greater than 3 million prospective gross acres. Twenty wells to 25 wells are expected to be drilled in the Wolfcamp A, B and D intervals. Another 10 wells to 15 wells are expected to be drilled in the Jo Mill, Middle Spraberry and the Lower Spraberry Shales. The cost for these wells is expected to average $7.5 million to $8.5 million per well assuming 7,000-foot laterals. This cost excludes $80 million of estimated “science” and infrastructure costs.
In the second quarter, Pioneer placed on production the Company’s first horizontal Wolfcamp B interval well in Martin County, Texas. The Mabee K #1H well had a 24-hour peak initial production rate of 1,572 BOEPD and a peak 30-day average production rate of 1,040 BOEPD, with an oil content of 76%. The well was completed utilizing a 27-stage hybrid fracture stimulation over the well’s perforated lateral length of 6,671 feet. The Mabee K #1H well confirms horizontal Wolfcamp B interval prospectivity approximately 30 miles north of Pioneer’s successful DL Hutt C #1H well in Midland County and 50 miles north of Pioneer’s first two horizontal Wolfcamp B interval wells in the Giddings area in Upton County.
Pioneer also placed on production the Company’s first horizontal Wolfcamp A interval well in Midland County during the second quarter. The DL Hutt C #2H well had a 24-hour peak initial production rate of 1,712 BOEPD and a peak 30-day average production rate of 1,107 BOEPD, with an oil content of 74%. The well was completed utilizing a 30-stage hybrid fracture stimulation over the well’s perforated lateral length of 7,380 feet. The strong performance of this well confirms horizontal Wolfcamp A interval prospectivity in Midland County.
The DL Hutt C #2H was completed on the same lease as Pioneer’s initial Wolfcamp B interval well in Midland County – the DL Hutt C #1H well. This Wolfcamp B interval well has been the best horizontal well drilled in the Wolfcamp Shale play to date, with an initial 24-hour peak production rate of 1,693 BOEPD and an average peak 30-day rate of 1,402 BOEPD. The well, which has a perforated lateral length of 7,380 feet, has been on production for six months and has produced a total of 140 MBOE with an oil content of 75%. The performance of this well is substantially above the 650 MBOE estimated ultimate recovery (EUR) type curve for the first two horizontal Wolfcamp B interval wells in the Giddings area.
The Company increased its horizontal rig count in the northern Spraberry/Wolfcamp drilling area from one rig to five rigs during the second quarter, with a further increase to eight rigs expected in 2014. The five-rig program is currently focused in Midland and Martin counties and consists of two rigs drilling Wolfcamp Shale appraisal wells, two rigs drilling Jo Mill and Spraberry Shale appraisal wells and one rig drilling Wolfcamp development wells on the Hutt lease. The Company is planning to move two of the rigs approximately 15 miles northwest of the Mabee K #1H well during the third quarter to drill Pioneer’s first Wolfcamp and Spraberry Shale interval horizontal wells in Andrews County. All wells are being drilled on two-well pads to gain efficiencies; therefore, the wells will not be completed until after the second well on each pad is drilled. It is expected to take 120 to 150 days from the time the first well on a two-well pad is spud until both wells on the pad are placed on production. This includes the extra time required for “science” and appraisal activities.
More specifically, Pioneer expects to add production from 20 new horizontal wells in the northern Spraberry/Wolfcamp area during the second half of 2013. This includes eight Wolfcamp B interval wells, four Wolfcamp D interval wells, three Jo Mill interval wells, four Lower Spraberry interval wells and one Middle Spraberry interval well. Since six of these wells are not expected to be placed on production until the latter part of the third quarter and the remainder during the fourth quarter, most of the production growth impact from these wells is expected to be in the fourth quarter.
The Company closed its joint venture transaction with Sinochem on May 31, resulting in the sale of 40% of Pioneer’s interest in approximately 207,000 net acres leased by the Company in the highly prospective horizontal Wolfcamp Shale play in the southern portion of the Spraberry Trend Area field for a total price of $1.8 billion, including normal closing adjustments. Pioneer retained 60% of its interest in the Wolfcamp and deeper horizons, with Sinochem receiving 40% of Pioneer’s interest. Pioneer continues as operator and retains its current working interests in all horizons shallower than the Wolfcamp horizon.
At closing, Sinochem paid $631 million in cash to Pioneer, of which $522 million was the up-front portion of the transaction price and $109 million was Sinochem’s 40% share of net expenditures in the joint venture area from the December 1, 2012 effective date of the transaction to the closing date. Sinochem will pay the remaining $1.2 billion of the transaction price by carrying 75% of Pioneer’s share of future drilling and facilities costs until the drilling carry is fully utilized.
The Company placed 22 new horizontal wells on production in the southern joint venture area during the second quarter, with 24-hour peak initial production rates up to approximately 1,000 BOEPD. Well performance across the area continues to meet expectations and reinforces the Company’s estimate that wells in this area will deliver an average EUR of at least 575 MBOE over the life of the well.
Pioneer operated seven rigs in the southern Wolfcamp joint venture area during the first half of 2013 and plans to continue at this level through the end of the year. An increase of three rigs per year is expected in 2014 and 2015. This equates to drilling 86 wells in 2013, 120 wells in 2014 and 165 wells in 2015. The 2013 drilling program continues to focus on delineating acreage and testing multiple Wolfcamp intervals. Approximately 70% of the wells drilled in this area during 2013 will be on three-well pads. It is taking approximately 150 days from the time the first well on a three-well pad is spud until all three wells on the pad are placed on production. Downspacing with staggered intervals (e.g., Upper B interval and Lower B interval) is also being tested down to 80-acre spacing.
The cost for horizontal development wells in the southern joint venture area ranges from $7.5 million to $8.0 million for an 8,300-foot lateral well. This includes the benefits of lower slickwater fracture stimulation costs and declining hybrid fracture stimulation costs. “Science” expenditures of $20 million have been included in the 2013 joint venture area drilling budget for coring, open-hole logging, micro-seismic and 3-D seismic. The Company expects to drill approximately 20 horizontal wells with extended lateral lengths to approximately 10,000 feet during 2013. These longer lateral wells are expected to generate an EUR increase of 40% to 60% at an incremental cost of 20%.
Pioneer is also operating 15 vertical rigs in the Spraberry field during 2013, which are expected to drill approximately 300 wells. These rigs are required to meet continuous drilling obligations. Approximately 90% of the 300 wells in the 2013 vertical drilling program are expected to be completed in the deeper Strawn and Atoka intervals. The Company estimates that 15 rigs to 20 rigs are required to keep vertical production flat. Pioneer drilled 73 vertical wells in the second quarter and placed 90 vertical wells on production as a result of decreasing the Company’s vertical frac bank (wells drilled in prior periods but not completed at that time) by 17 wells. The frac bank was also reduced by 55 wells during the first quarter. These frac bank reductions allowed vertical production to increase slightly during the first quarter and second quarter, but vertical production during the third and fourth quarters is expected to decline somewhat from the second quarter since no further frac bank reductions are anticipated.
Second quarter production from the entire Spraberry/Wolfcamp area averaged 80 MBOEPD, an increase of 5 MBOEPD, or 7%, from the first quarter of 2013. This included horizontal production of 8 MBOEPD and vertical production of 72 MBOEPD. Second quarter production was negatively impacted by the loss of approximately 1,400 BOEPD due to unexpected ethane rejection in the Midkiff/Benedum gas processing system due to low ethane prices. Ethane rejection is expected to continue during the second half of the year due to low ethane prices and is forecasted to reduce production during the second half of 2013 by approximately 2 MBOEPD.
The new Driver gas processing plant, with a capacity of 200 million cubic feet per day (MMCFPD), came online as expected in April. Another new plant, with an aggregate capacity of 200 MMCFPD, has recently been announced, with 100 MMCFPD expected to be available in late 2014 and the remaining 100 MMCFPD available in 2015.
For 2013, total Spraberry/Wolfcamp production is forecasted to grow to 77 MBOEPD to 80 MBOEPD, an increase of 17% to 21% compared to 2012. The bottom end of the range has been increased from the previous forecast of 14%, while the top end of the range has been held constant at 21% despite the negative impact on production associated with rejecting ethane. This change reflects the strong performance by this asset over the first half of 2013 and expectations that new horizontal production will more than offset expected declines in vertical production over the second half of the year. The 2013 growth forecast for the Spraberry/Wolfcamp area also reflects that the vertical rig count decreased from an average of 32 rigs in 2012 to 15 rigs in 2013, while the horizontal rig count increased from an average of three rigs in 2012 to an average level of 12 rigs in 2013. Pioneer expects horizontal production to increase from an average of 2 MBOEPD in 2012 to 11 MBOEPD to 14 MBOEPD in 2013.
In the liquids-rich Eagle Ford Shale play in South Texas, the Company drilled 33 wells in the second quarter and placed 23 wells on production. Pioneer increased its Eagle Ford Shale production from 37 MBOEPD in the first quarter to 38 MBOEPD in the second quarter, achieving another record production level. Strong well performance continues to drive this growth. The Company expects 2013 production to range from 38 MBOEPD to 42 MBOEPD, an increase of 36% to 50% compared to full-year 2012 production of 28 MBOEPD.
Pioneer expects to drill approximately 130 Eagle Ford Shale wells in 2013 at a cost of $7 million to $8 million per well for lateral lengths of approximately 5,500 feet. Essentially all of these wells will be liquids-rich wells, with minimal dry gas drilling expected during the year. Pioneer’s drilling operations in the Eagle Ford Shale continue to become more efficient. The number of wells drilled from pads, as opposed to single-well locations, is expected to increase from 45% of the wells drilled in 2012 to 80% of the wells drilled in 2013, reflecting that most of Pioneer’s acreage is now held by production. Pad sizes range from two wells to six wells per pad. None of the wells are fracture stimulated until all of the wells on a pad are drilled. Therefore, the timing between when the first well on a pad is spud and when the pad is placed on production is dependent on how many wells are drilled from the pad and is significantly extended compared to single well drilling. For perspective, it is taking 100 days to 120 days from the time the first well on a three-well pad is spud until all three wells on the pad are placed on production. Consequently, the Company’s planned pad drilling over the remainder of the year is expected to result in “lumpy” quarter-to-quarter production growth. The Company placed 58 wells on production during the first half of 2013 and expects to place 79 wells on production during the second half. As a result of the second half 2013 planned pad drilling schedule, most of the Eagle Ford Shale production growth is expected to be in the fourth quarter.
Pad drilling saves $600 thousand to $700 thousand per well and will result in Pioneer being able to drill 130 wells with 10 rigs in 2013 compared to drilling a similar number of wells in 2012 with 12 rigs. A downspacing pilot is underway to test spacing down to 40 acres. Pioneer will also be testing longer lateral lengths up to 10,000 feet in certain areas.
Pioneer has been using lower-cost white sand instead of ceramic proppant to fracture stimulate wells drilled in shallower areas of the Eagle Ford Shale field. The Company is now expanding the use of white sand proppant to deeper areas of the field to further assess its performance limits. The Company fracture stimulated 39 wells with white sand proppant in the first half of 2013, with a savings of approximately $1.1 million per well, up from a savings of approximately $700 thousand per well. Early performance from wells fracture stimulated with white sand over the past two years has been similar to direct offset ceramic-stimulated wells. Pioneer is continuing to monitor the performance of these wells and expects that approximately 75% of its 2013 drilling program will use the lower-cost white sand proppant.
2013 Capital Budget
Pioneer’s capital program for 2013 remains unchanged at $3 billion (includes land capital but excludes asset retirement obligations, capitalized interest and geological and geophysical G&A). The capital program includes $2.75 billion of drilling capital and $240 million for vertical integration additions and construction of new field and office buildings. Drilling capital expenditures totaled $717 million in the second quarter of 2013 and $1.5 billion for the first six months of 2013.
The 2013 capital budget is expected to be funded from forecasted operating cash flow of $2.3 billion, assuming commodity prices for the remainder of 2013 of $95 per barrel for oil and $4.00 per thousand cubic feet (MCF) for gas and from cash on the balance sheet.
Pioneer’s net debt as of June 30, 2013 was $2.1 billion. Net debt-to-book capitalization was 22%, down from 26% at the end of the first quarter. The Company will continue to target a net debt-to-book capitalization below 35% and net debt-to-operating cash flow below 1.5 times.
Second Quarter 2013 Financial Review
Sales volumes for the second quarter of 2013 averaged 176 MBOEPD. Oil sales averaged 75 thousand barrels per day (MBPD), natural gas liquids (NGL) sales averaged 34 MBPD and gas sales averaged 400 MMCFPD.
The average realized price for oil was $90.82 per barrel. The average realized price for NGLs was $28.19 per barrel and the average realized price for gas was $3.74 per MCF.
Production costs averaged $14.56 per barrel oil equivalent (BOE). Depreciation, depletion and amortization (DD&A) expense averaged $15.57 per BOE. Exploration and abandonment costs were $24 million, principally comprised of $4 million associated with drilling and acreage abandonments, $5 million for seismic data and $15 million for personnel costs. General and administrative expense totaled $67 million. Interest expense was $43 million and other expense was $19 million.
Third Quarter 2013 Financial Outlook
The Company’s third quarter 2013 outlook for certain operating and financial items is provided below.
Production is forecasted to average 174 MBOEPD to 179 MBOEPD. This forecast assumes that third quarter production in the Spraberry/Wolfcamp area will be negatively impacted by approximately 2 MBOEPD as a result of ethane rejection due to low ethane prices. The guidance for the third quarter assumes that Pioneer will not reject ethane in any of the Company’s other operating areas due to low ethane prices.
Production costs are expected to average $14.00 per BOE to $16.00 per BOE. DD&A expense is expected to average $14.50 per BOE to $16.50 per BOE. Total exploration and abandonment expense is forecasted to be $25 million to $35 million.
General and administrative expense is expected to be $65 million to $70 million, interest expense is expected to be $43 million to $48 million and other expense is expected to be $25 million to $35 million. Accretion of discount on asset retirement obligations is expected to be $3 million to $5 million.
Noncontrolling interest in consolidated subsidiaries’ income, excluding unrealized derivative mark-to-market adjustments, is expected to be $8 million to $11 million, primarily reflecting the public ownership in Pioneer Southwest Energy Partners L.P.
The Company’s effective income tax rate is expected to range from 35% to 40%. Current income taxes are expected to be $10 million to $15 million and are primarily attributable to federal alternative minimum tax and state taxes.
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, August 1, 2013, at 9:00 a.m. Central Time, Pioneer will discuss its financial and operating results for the quarter ended June 30, 2013, with an accompanying presentation. Instructions for listening to the call and viewing the accompanying presentation are shown below.
Internet: www.pxd.com
Select “Investors,” then “Earnings & Webcasts” to listen to the discussion, view the presentation and see other related material.
Telephone: Dial (877) 795-3599 confirmation code: 1325397 five minutes before the call. View the presentation via Pioneer’s internet address above.
A replay of the webcast will be archived on Pioneer’s website. A telephone replay will be available through August 26, 2013, by dialing (888) 203-1112 confirmation code: 1325397.
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 Pioneer’s website at 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, availability of equipment, services, resources and personnel required to complete the Company’s 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, the financial strength of counterparties to Pioneer’s credit facility and derivative contracts and the purchasers of Pioneer’s oil, NGL and gas production, 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 an industrial sand mining business 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,” “estimated ultimate recovery,” “EUR” 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. 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 thousands) | |||||||||||
| June 30, 2013 | December 31, 2012 | ||||||||||
| ASSETS | |||||||||||
| Current assets: | |||||||||||
| Cash and cash equivalents | $ | 695,625 | $ | 229,396 | |||||||
| Accounts receivable, net | 350,488 | 320,153 | |||||||||
| Income taxes receivable | 927 | 7,447 | |||||||||
| Inventories | 198,650 | 197,056 | |||||||||
| Prepaid expenses | 23,634 | 13,438 | |||||||||
| Derivatives | 191,697 | 279,119 | |||||||||
| Other current assets, net | 4,171 | 3,746 | |||||||||
| Total current assets | 1,465,192 | 1,050,355 | |||||||||
| Property, plant and equipment, at cost: | |||||||||||
| Oil and gas properties, using the successful efforts method of accounting | 15,506,230 | 14,491,263 | |||||||||
| Accumulated depletion, depreciation and amortization | (4,859,716 | ) | (4,412,913 | ) | |||||||
| Total property, plant and equipment | 10,646,514 | 10,078,350 | |||||||||
| Goodwill | 279,687 | 298,142 | |||||||||
| Other property and equipment, net | 1,231,127 | 1,217,694 | |||||||||
| Investment in unconsolidated affiliate | 228,475 | 204,129 | |||||||||
| Derivatives | 137,898 | 55,257 | |||||||||
| Other assets, net | 173,694 | 165,103 | |||||||||
| $ | 14,162,587 | $ | 13,069,030 | ||||||||
| LIABILITIES AND EQUITY | |||||||||||
| Current liabilities: | |||||||||||
| Accounts payable | $ | 878,683 | $ | 826,877 | |||||||
| Interest payable | 61,464 | 68,083 | |||||||||
| Income taxes payable | 938 | 208 | |||||||||
| Deferred income taxes | 25,344 | 86,481 | |||||||||
| Derivatives | 6,453 | 13,416 | |||||||||
| Other current liabilities | 39,246 | 39,725 | |||||||||
| Total current liabilities | 1,012,128 | 1,034,790 | |||||||||
| Long-term debt | 2,823,428 | 3,721,193 | |||||||||
| Derivatives | — | 12,307 | |||||||||
| Deferred income taxes | 2,390,144 | 2,140,416 | |||||||||
| Other liabilities | 288,730 | 293,016 | |||||||||
| Equity | 7,648,157 | 5,867,308 | |||||||||
| $ | 14,162,587 | $ | 13,069,030 | ||||||||
| PIONEER NATURAL RESOURCES COMPANY | ||||||||||||||||||||
| UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS | ||||||||||||||||||||
| (in thousands, except per share data) | ||||||||||||||||||||
|
Three Months Ended June 30, |
Six Months Ended June 30, |
|||||||||||||||||||
| 2013 | 2012 | 2013 | 2012 | |||||||||||||||||
| Revenues and other income: | ||||||||||||||||||||
| Oil and gas | $ | 845,136 | $ | 641,737 | $ | 1,632,991 | $ | 1,360,693 | ||||||||||||
| Interest and other | 1,159 | (714 | ) | 20,474 | 21,194 | |||||||||||||||
| Derivative gains, net | 144,445 | 275,812 | 102,202 | 367,562 | ||||||||||||||||
| Gain on disposition of assets, net | 190,987 | 1,140 | 215,404 | 44,736 | ||||||||||||||||
| 1,181,727 | 917,975 | 1,971,071 | 1,794,185 | |||||||||||||||||
| Costs and expenses: | ||||||||||||||||||||
| Oil and gas production | 179,488 | 150,081 | 348,628 | 281,862 | ||||||||||||||||
| Production and ad valorem taxes | 53,837 | 44,495 | 108,134 | 90,291 | ||||||||||||||||
| Depletion, depreciation and amortization | 249,590 | 200,921 | 480,353 | 382,339 | ||||||||||||||||
| Impairment of oil and gas properties | — | 444,880 | — | 444,880 | ||||||||||||||||
| Exploration and abandonments | 23,973 | 37,178 | 51,600 | 90,465 | ||||||||||||||||
| General and administrative | 66,654 | 54,957 | 130,405 | 118,024 | ||||||||||||||||
| Accretion of discount on asset retirement obligations | 3,166 | 2,444 | 6,319 | 4,874 | ||||||||||||||||
| Interest | 42,805 | 49,008 | 93,540 | 95,866 | ||||||||||||||||
| Other | 18,711 | 30,651 | 40,060 | 54,258 | ||||||||||||||||
| 638,224 | 1,014,615 | 1,259,039 | 1,562,859 | |||||||||||||||||
| Income (loss) from continuing operations before income taxes | 543,503 | (96,640 | ) | 712,032 | 231,326 | |||||||||||||||
| Income tax benefit (provision) | (192,029 | ) | 45,086 | (251,358 | ) | (72,617 | ) | |||||||||||||
| Income (loss) from continuing operations | 351,474 | (51,554 | ) | 460,674 | 158,709 | |||||||||||||||
| Income (loss) from discontinued operations, net of tax | — | 12,017 | (465 | ) | 22,712 | |||||||||||||||
| Net income (loss) | 351,474 | (39,537 | ) | 460,209 | 181,421 | |||||||||||||||
| Net income attributable to noncontrolling interests | (14,211 | ) | (30,855 | ) | (22,283 | ) | (37,194 | ) | ||||||||||||
| Net income (loss) attributable to common stockholders | $ | 337,263 | $ | (70,392 | ) | $ | 437,926 | $ | 144,227 | |||||||||||
| Basic earnings per share: | ||||||||||||||||||||
| Income (loss) from continuing operations attributable to common stockholders | $ | 2.42 | $ | (0.67 | ) | $ | 3.24 | $ | 0.98 | |||||||||||
| Income (loss) from discontinued operations attributable to common stockholders | — | 0.10 | — | 0.18 | ||||||||||||||||
| Net income (loss) attributable to common stockholders | $ | 2.42 | $ | (0.57 | ) | $ | 3.24 | $ | 1.16 | |||||||||||
| Diluted earnings per share: | ||||||||||||||||||||
| Income (loss) from continuing operations attributable to common stockholders | $ | 2.40 | $ | (0.67 | ) | $ | 3.19 | $ | 0.95 | |||||||||||
| Income (loss) from discontinued operations attributable to common stockholders | — | 0.10 | — | 0.18 | ||||||||||||||||
| Net income (loss) attributable to common stockholders | $ | 2.40 | $ | (0.57 | ) | $ | 3.19 | $ | 1.13 | |||||||||||
| Weighted average shares outstanding: | ||||||||||||||||||||
| Basic | 137,539 | 123,028 | 133,263 | 122,754 | ||||||||||||||||
| Diluted | 138,829 | 123,028 | 135,762 | 125,772 | ||||||||||||||||
| PIONEER NATURAL RESOURCES COMPANY | |||||||||||||||||||
| UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | |||||||||||||||||||
| (in thousands) | |||||||||||||||||||
|
Three Months Ended June 30, |
Six Months Ended June 30, |
||||||||||||||||||
| 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
| Cash flows from operating activities: | |||||||||||||||||||
| Net income (loss) | $ | 351,474 | $ | (39,537 | ) | $ | 460,209 | $ | 181,421 | ||||||||||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||||||||||||||||||
| Depletion, depreciation and amortization | 249,590 | 200,921 | 480,353 | 382,339 | |||||||||||||||
| Impairment of oil and gas properties | — | 444,880 | — | 444,880 | |||||||||||||||
| Exploration expenses, including dry holes | 4,339 | 12,567 | 12,293 | 39,730 | |||||||||||||||
| Deferred income taxes | 181,844 | (48,580 | ) | 233,738 | 57,291 | ||||||||||||||
| Gain on disposition of assets, net | (190,987 | ) | (1,140 | ) | (215,404 | ) | (44,736 | ) | |||||||||||
| Accretion of discount on asset retirement obligations | 3,166 | 2,444 | 6,319 | 4,874 | |||||||||||||||
| Discontinued operations | — | 2,020 | (158 | ) | 3,597 | ||||||||||||||
| Interest expense | 4,062 | 8,282 | 8,907 | 18,152 | |||||||||||||||
| Derivative related activity | (110,372 | ) | (116,757 | ) | (14,488 | ) | (144,000 | ) | |||||||||||
| Amortization of stock-based compensation | 16,632 | 15,884 | 34,027 | 30,970 | |||||||||||||||
| Amortization of deferred revenue | — | (10,460 | ) | — | (20,919 | ) | |||||||||||||
| Other noncash items | (1,783 | ) | 1,671 | (4,706 | ) | (7,513 | ) | ||||||||||||
| Change in operating assets and liabilities, net of effects from acquisitions and dispositions: | |||||||||||||||||||
| Accounts receivable, net | 8,875 | 54,876 | (32,928 | ) | 33,881 | ||||||||||||||
| Income taxes receivable | 467 | (2,859 | ) | 6,520 | (1,452 | ) | |||||||||||||
| Inventories | (1,504 | ) | (2,291 | ) | (679 | ) | (33,318 | ) | |||||||||||
| Prepaid expenses | (10,297 | ) | (14,838 | ) | (10,196 | ) | (13,425 | ) | |||||||||||
| Other current assets | 3,173 | (11,334 | ) | 2,537 | (8,846 | ) | |||||||||||||
| Accounts payable | 48,400 | 11,254 | (9,172 | ) | 30,580 | ||||||||||||||
| Interest payable | 23,969 | 21,999 | (6,620 | ) | 82 | ||||||||||||||
| Income taxes payable | 646 | (24,848 | ) | 730 | (7,907 | ) | |||||||||||||
| Other current liabilities | (5,908 | ) | (4,830 | ) | (15,422 | ) | (20,271 | ) | |||||||||||
| Net cash provided by operating activities | 575,786 | 499,324 | 935,860 | 925,410 | |||||||||||||||
| Net cash used in investing activities | (106,520 | ) | (1,142,400 | ) | (813,696 | ) | (1,822,066 | ) | |||||||||||
| Net cash provided by (used in) financing activities | (203,939 | ) | 643,927 | 344,065 | 676,941 | ||||||||||||||
| Net increase (decrease) in cash and cash equivalents | 265,327 | 851 | 466,229 | (219,715 | ) | ||||||||||||||
| Cash and cash equivalents, beginning of period | 430,298 | 316,918 | 229,396 | 537,484 | |||||||||||||||
| Cash and cash equivalents, end of period | $ | 695,625 | $ | 317,769 | $ | 695,625 | $ | 317,769 | |||||||||||
| PIONEER NATURAL RESOURCES COMPANY | ||||||||||||||||||
| UNAUDITED SUMMARY PRODUCTION AND PRICE DATA | ||||||||||||||||||
|
Three Months Ended June 30, |
Six Months Ended June 30, |
|||||||||||||||||
| 2013 | 2012 | 2013 | 2012 | |||||||||||||||
| Average Daily Sales Volumes from Continuing Operations: | ||||||||||||||||||
| Oil (Bbls) | 75,074 | 61,428 | 74,509 | 59,550 | ||||||||||||||
| Natural gas liquids ("NGL") (Bbls) | 34,415 | 26,960 | 33,706 | 27,222 | ||||||||||||||
| Gas (Mcf) | 400,329 | 372,713 | 392,128 | 371,068 | ||||||||||||||
| Total (BOE) | 176,211 | 150,506 | 173,570 | 148,617 | ||||||||||||||
| Average Reported Prices (a): | ||||||||||||||||||
| Oil (per Bbl) | $ | 90.82 | $ | 88.32 | $ | 89.71 | $ | 94.45 | ||||||||||
| NGL (per Bbl) | $ | 28.19 | $ | 32.62 | $ | 29.25 | $ | 37.26 | ||||||||||
| Gas (per Mcf) | $ | 3.74 | $ | 2.00 | $ | 3.45 | $ | 2.26 | ||||||||||
| Total (BOE) | $ | 52.71 | $ | 46.86 | $ | 51.98 | $ | 50.31 | ||||||||||
|
_____________ |
||||||||||||||||||
| (a) |
Average reported prices are attributable to continuing operations and, for 2012, include the results of hedging activities and amortization of volumetric production payment ("VPP") deferred revenue. During 2012, all remaining deferred hedge losses were transferred to earnings and, as of December 31, 2012, all VPP production volumes had been delivered and there were no further obligations under VPP contracts or deferred revenue. |
|
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- and unit-based awards with guaranteed dividend or distribution participation rights qualify as "participating securities" during their vesting periods. Participating securities participate in the Company's dividend or partnership distributions and are assumed to participate in the Company's undistributed income proportionate to their share of the weighted average outstanding common shares, but are not assumed to participate in the Company's net losses because they are not contractually obligated to do so. 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- and unit-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 (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 net income (loss) attributable to common stockholders and to diluted net income (loss) attributable to common stockholders for the three and six months ended June 30, 2013 and 2012:
|
Three Months Ended June 30, |
Six Months Ended June 30, |
||||||||||||||||||
| 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
| (in thousands) | |||||||||||||||||||
| Net income (loss) attributable to common stockholders | $ | 337,263 | $ | (70,392 | ) | $ | 437,926 | $ | 144,227 | ||||||||||
| Participating basic earnings | (4,584 | ) | (265 | ) | (5,586 | ) | (2,176 | ) | |||||||||||
| Basic net income (loss) attributable to common stockholders | 332,679 | (70,657 | ) | 432,340 | 142,051 | ||||||||||||||
| Reallocation of participating earnings | 73 | — | 124 | 154 | |||||||||||||||
| Diluted net income (loss) attributable to common stockholders | $ | 332,752 | $ | (70,657 | ) | $ | 432,464 | $ | 142,205 | ||||||||||
The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three and six months ended June 30, 2013 and 2012:
|
Three Months Ended June 30, |
Six Months Ended June 30, |
|||||||||||||
| 2013 | 2012 | 2013 | 2012 | |||||||||||
| (in thousands) | ||||||||||||||
| Weighted average common shares outstanding: | ||||||||||||||
| Basic | 137,539 | 123,028 | 133,263 | 122,754 | ||||||||||
| Dilutive common stock options | 137 | — | 147 | 205 | ||||||||||
| Convertible senior notes dilution | 954 | — | 2,193 | 2,642 | ||||||||||
| Contingently issuable performance unit shares | 199 | — | 159 | 171 | ||||||||||
| Diluted | 138,829 | 123,028 | 135,762 | 125,772 | ||||||||||
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES
(in
thousands)
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 June 30, |
Six Months Ended June 30, |
||||||||||||||||||
| 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
| Net income (loss) | $ | 351,474 | $ | (39,537 | ) | $ | 460,209 | $ | 181,421 | ||||||||||
| Depletion, depreciation and amortization | 249,590 | 200,921 | 480,353 | 382,339 | |||||||||||||||
| Exploration and abandonments | 23,973 | 37,178 | 51,600 | 90,465 | |||||||||||||||
| Impairment of oil and gas properties | — | 444,880 | — | 444,880 | |||||||||||||||
| Accretion of discount on asset retirement obligations | 3,166 | 2,444 | 6,319 | 4,874 | |||||||||||||||
| Interest expense | 42,805 | 49,008 | 93,540 | 95,866 | |||||||||||||||
| Income tax (benefit) provision | 192,029 | (45,086 | ) | 251,358 | 72,617 | ||||||||||||||
| Gain on disposition of assets, net | (190,987 | ) | (1,140 | ) | (215,404 | ) | (44,736 | ) | |||||||||||
| (Income) loss from discontinued operations | — | (12,017 | ) | 465 | (22,712 | ) | |||||||||||||
| Derivative related activity | (110,372 | ) | (116,757 | ) | (14,488 | ) | (144,000 | ) | |||||||||||
| Amortization of stock-based compensation | 16,632 | 15,884 | 34,027 | 30,970 | |||||||||||||||
| Amortization of deferred revenue | — | (10,460 | ) | — | (20,919 | ) | |||||||||||||
| Other noncash items | (1,783 | ) | 1,671 | (4,706 | ) | (7,513 | ) | ||||||||||||
| EBITDAX (a) | 576,527 | 526,989 | 1,143,273 | 1,063,552 | |||||||||||||||
| Cash interest expense | (38,743 | ) | (40,726 | ) | (84,633 | ) | (77,714 | ) | |||||||||||
| Current income tax provision | (10,185 | ) | (3,494 | ) | (17,620 | ) | (15,326 | ) | |||||||||||
| Discretionary cash flow (b) | 527,599 | 482,769 | 1,041,020 | 970,512 | |||||||||||||||
| Discontinued operations cash activity | — | 14,037 | (623 | ) | 26,309 | ||||||||||||||
| Cash exploration expense | (19,634 | ) | (24,611 | ) | (39,307 | ) | (50,735 | ) | |||||||||||
| Changes in operating assets and liabilities (c) | 67,821 | 27,129 | (65,230 | ) | (20,676 | ) | |||||||||||||
| Net cash provided by operating activities | $ | 575,786 | $ | 499,324 | $ | 935,860 | $ | 925,410 | |||||||||||
|
_____________ |
|||||||||||||||||||
| (a) |
“EBITDAX” represents earnings before depletion, depreciation and amortization expense; exploration and abandonments; impairment of oil and gas properties; accretion of discount on asset retirement obligations; interest expense; income taxes; gain on the disposition of assets, net; (income) loss from discontinued operations; noncash derivative related activity; amortization of stock-based compensation; amortization of deferred revenue and other noncash 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. | |
| (c) | Changes in operating assets and liabilities are primarily due to the timing of payments for working capital items. | |
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES (continued)
(in
thousands, except per share data)
Adjusted income excluding unrealized mark-to-market ("MTM") derivative gains, and adjusted income excluding unrealized MTM derivative gains and unusual items, as presented in this press release, are presented and reconciled to Pioneer's net income 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. Unrealized 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 income attributable to common stockholders for the three months ended June 30, 2013, as determined in accordance with GAAP, to income adjusted for unrealized MTM derivative gains and adjusted income excluding unrealized MTM derivative gains and unusual items for that quarter.
|
After-tax |
Amounts
Per Share |
||||||||||
| Net income attributable to common stockholders | $ | 337,263 | $ | 2.40 | |||||||
|
Unrealized MTM derivative gains |
(66,753 | ) | (0.47 | ) | |||||||
| Income adjusted for unrealized MTM derivative gains | 270,510 | 1.93 | |||||||||
| Gain on disposition of assets (principally attributable to Southern Wolfcamp joint venture transaction) | (112,457 | ) | (0.80 | ) | |||||||
|
Alaska production tax credit recoveries |
(4,008 | ) | (0.03 | ) | |||||||
| Adjusted income excluding unrealized MTM derivative gains and unusual items | $ | 154,045 | $ | 1.10 | |||||||
| PIONEER NATURAL RESOURCES COMPANY | |||||||||||||||||||||||||
| SUPPLEMENTAL INFORMATION | |||||||||||||||||||||||||
|
Open Commodity Derivative Positions as of July 30, 2013 |
|||||||||||||||||||||||||
| (Volumes are average daily amounts) | |||||||||||||||||||||||||
| 2013 | Year Ending December 31, | ||||||||||||||||||||||||
|
Third |
Fourth |
2014 | 2015 | 2016 | |||||||||||||||||||||
| Average Daily Oil Production Associated with Derivatives (Bbl): | |||||||||||||||||||||||||
| Collar contracts with short puts: | |||||||||||||||||||||||||
| Volume | 68,274 | 69,000 | 69,000 | 65,000 | 20,000 | ||||||||||||||||||||
| NYMEX price: | |||||||||||||||||||||||||
| Ceiling | $ | 119.75 | $ | 120.55 | $ | 114.05 | $ | 99.32 | $ | 93.26 | |||||||||||||||
| Floor | $ | 92.23 | $ | 91.39 | $ | 93.70 | $ | 89.00 | $ | 85.00 | |||||||||||||||
| Short put | $ | 74.39 | $ | 74.22 | $ | 77.61 | $ | 74.00 | $ | 70.00 | |||||||||||||||
| Swap contracts: | |||||||||||||||||||||||||
| Volume | 7,476 | 9,750 | 10,000 | — | — | ||||||||||||||||||||
| NYMEX price | $ | 93.60 | $ | 95.57 | $ | 93.87 | $ | — | $ | — | |||||||||||||||
| Rollfactor swap contracts: | |||||||||||||||||||||||||
| Volume | 7,630 | 11,000 | 19,000 | — | — | ||||||||||||||||||||
| NYMEX roll price (a) | $ | 0.63 | $ | 0.85 | $ | 0.45 | $ | — | $ | — | |||||||||||||||
| Basis swap contracts: | |||||||||||||||||||||||||
| Cushing to LLS index swap volume | — | 3,000 | — | — | — | ||||||||||||||||||||
| Price differential ($/Bbl) (b) | $ | — | $ | 8.53 | $ | — | $ | — | $ | — | |||||||||||||||
| Average Daily NGL Production Associated with Derivatives (Bbl): | |||||||||||||||||||||||||
| Collar contracts with short puts (c): | |||||||||||||||||||||||||
| Volume | 1,064 | 1,064 | 1,000 | — | — | ||||||||||||||||||||
| Index price: | |||||||||||||||||||||||||
| Ceiling | $ | 105.28 | $ | 105.28 | $ | 109.50 | $ | — | $ | — | |||||||||||||||
| Floor | $ | 89.30 | $ | 89.30 | $ | 95.00 | $ | — | $ | — | |||||||||||||||
| Short put | $ | 75.20 | $ | 75.20 | $ | 80.00 | $ | — | $ | — | |||||||||||||||
| Collar contracts (d): | |||||||||||||||||||||||||
| Volume | 2,500 | 2,500 | 3,000 | — | — | ||||||||||||||||||||
| Index price: | |||||||||||||||||||||||||
| Ceiling | $ | 12.68 | $ | 12.68 | $ | 13.72 | $ | — | $ | — | |||||||||||||||
| Floor | $ | 10.50 | $ | 10.50 | $ | 10.78 | $ | — | $ | — | |||||||||||||||
| Average Daily Gas Production Associated with Derivatives (MMBtu): | |||||||||||||||||||||||||
| Collar contracts with short puts: | |||||||||||||||||||||||||
| Volume | — | — | 115,000 | 285,000 | 20,000 | ||||||||||||||||||||
| NYMEX price: | |||||||||||||||||||||||||
| Ceiling | $ | — | $ | — | $ | 4.70 | $ | 5.07 | $ | 5.36 | |||||||||||||||
| Floor | $ | — | $ | — | $ | 4.00 | $ | 4.00 | $ | 4.00 | |||||||||||||||
| Short put | $ | — | $ | — | $ | 3.00 | $ | 3.00 | $ | 3.00 | |||||||||||||||
| Collar contracts: | |||||||||||||||||||||||||
| Volume | 152,500 | 152,500 | — | — | — | ||||||||||||||||||||
| NYMEX price: | |||||||||||||||||||||||||
| Ceiling | $ | 6.22 | $ | 6.22 | $ | — | $ | — | $ | — | |||||||||||||||
| Floor | $ | 4.98 | $ | 4.98 | $ | — | $ | — | $ | — | |||||||||||||||
| Swap contracts: | |||||||||||||||||||||||||
| Volume | 172,500 | 165,870 | 175,000 | 20,000 | — | ||||||||||||||||||||
| NYMEX price (e) | $ | 5.05 | $ | 5.10 | $ | 4.02 | $ | 4.31 | $ | — | |||||||||||||||
| Basis swap contracts: | |||||||||||||||||||||||||
| Permian Basin index swap volume (f) | 52,500 | 52,500 | 10,000 | 10,000 | — | ||||||||||||||||||||
| Price differential ($/MMBtu) | $ | (0.23 | ) | $ | (0.23 | ) | $ | (0.15 | ) | $ | (0.13 | ) | $ | — | |||||||||||
| Mid-Continent index swap volume (f) | 50,000 | 50,000 |
35,082 |
20,000 | — | ||||||||||||||||||||
| Price differential ($/MMBtu) | $ | (0.30 | ) | $ | (0.30 | ) | $ | (0.19 | ) | $ | (0.21 | ) | $ | — | |||||||||||
| Gulf Coast index swap volume (f) | 60,000 | 60,000 | — | — | — | ||||||||||||||||||||
| Price differential ($/MMBtu) | $ | (0.14 | ) | $ | (0.14 | ) | $ | — | $ | — | $ | — | |||||||||||||
|
_____________ |
|||||||||||||||||||||||||
| (a) | Represent swaps that fix the difference between (i) each day's price per Bbl of West Texas Intermediate oil ("WTI") for the first nearby month less (ii) the price per Bbl of WTI for the second nearby NYMEX month, multiplied by .6667; plus (iii) each day's price per Bbl of WTI for the first nearby month less (iv) the price per Bbl of WTI for the third nearby NYMEX month, multiplied by .3333. | |
| (b) | Represent swaps that fix the basis differential between Cushing WTI and Louisiana Light Sweet crude ("LLS"). | |
| (c) | Represent collar contracts with short puts that reduce the price volatility of natural gasoline forecasted for sale by the Company at Mont Belvieu, Texas-posted prices. | |
| (d) | Represent collar contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices. | |
| (e) | Represents the NYMEX Henry Hub index price on the derivative trade date. | |
| (f) | Represent swaps that fix the basis differentials between the indices price at which the Company sells its Permian Basin, Mid-Continent and Gulf Coast gas and the NYMEX Henry Hub index price used in gas swap and collar contracts. | |
Interest rate derivatives. During the three months ended June 30, 2013, the Company terminated interest rate derivative contracts for the 10-year period ending in December 2025 for proceeds of $482 thousand. In addition, during the period from July 1, 2013, to July 30, 2013, the Company entered into interest rate derivative contracts whereby the Company will receive a fixed interest rate of 3.95 percent in exchange for paying a floating interest rate comprised of the three-month LIBOR plus an average rate of 1.21 percent on a notional amount of $175 million through July 15, 2022.
Derivative Gains, Net
(in thousands)
The following table summarizes net derivative gains and losses that the Company has recorded in it earnings for the three and six months ended June 30, 2013:
|
Three Months Ended |
Six Months Ended |
||||||||||
| Noncash changes in fair value: | |||||||||||
| Oil derivative gains | $ | 54,248 | $ | 55,873 | |||||||
| NGL derivative gains | 1,945 | 2,835 | |||||||||
| Gas derivative gains (losses) | 48,464 | (53,966 | ) | ||||||||
| Marketing derivative gains (losses) | (69 | ) | 22 | ||||||||
| Interest rate derivative gains | 5,784 | 9,724 | |||||||||
| Total noncash derivative gains, net (a) | 110,372 | 14,488 | |||||||||
| Cash settled changes in fair value: | |||||||||||
| Oil derivative gains | 7,329 | 14,849 | |||||||||
| NGL derivative gains (losses) | 377 | (35 | ) | ||||||||
| Gas derivative gains | 25,881 | 72,586 | |||||||||
| Marketing derivative gains (losses) | 4 | (168 | ) | ||||||||
| Interest rate derivative gains | 482 | 482 | |||||||||
| Total cash derivative gains, net | 34,073 | 87,714 | |||||||||
| Total derivative gains, net | $ | 144,445 | $ | 102,202 | |||||||
|
_____________ |
|||||||||||
|
(a) |
Total noncash net derivative gains, include $4.4 million and $4.7 million, respectively, of net gains attributable to noncontrolling interests in consolidated subsidiaries during the three and six months ended June 30, 2013. |