Concho Resources Inc. reported financial and operating results for the three months and year ended December 31, 2013.
Production for 2013 totaled 33.6 MMBoe (21.1 million barrels of oil (“MMBbls”) and 75.1 billion cubic feet of natural gas (“Bcf”)), an increase of 20% as compared to 28.0 MMBoe (16.9 MMBbls of crude oil and 66.6 Bcf of natural gas) produced in 2012 from continuing operations.
In the fourth quarter of 2013 production was 8.9 MMBoe (5.8 MMBbls of crude oil and 19.0 Bcf of natural gas), or 97.0 thousand barrels of oil equivalent (“MBoe”) per day, a 14% increase over the comparable prior-year period of 7.8 MMBoe (4.7 MMBbls of crude oil and 18.5 Bcf of natural gas). Sequentially, Concho’s total fourth quarter 2013 production increased 3% as compared to the previous quarter of 8.7 MBoe (5.4 MMBbls of crude oil and 19.6 Bcf of natural gas) and crude oil production during the fourth quarter increased 7% over the previous quarter, despite the winter weather-related curtailments. The fourth quarter of 2013 was Concho’s 16th consecutive quarter to increase crude oil production from continuing operations over the immediately previous quarter.
“We are in a unique position of hitting our execution stride just as we are beginning to define the true depth and scale of the resource potential that exists across our assets,” commented Tim Leach, Chairman, Chief Executive Officer and President. “Concho delivered substantial crude oil growth during 2013 while building the largest horizontal development program in the Permian Basin. As we enter the first year of our acceleration plan to double production by year-end 2016, we have significant momentum and opportunity to continue our track record of solid execution and growth.”
For 2013, the Company reported net income of $251.0 million, or $2.39 per diluted share, as compared to net income of $431.7 million, or $4.15 per diluted share, for 2012. The Company’s 2013 results were impacted by several non-cash and unusual items including: (1) a $123.7 million loss on derivatives not designated as hedges, (2) $32.3 million in cash payments on commodity derivatives, (3) $65.4 million of impairments of long-lived assets, (4) $49.8 million of leasehold abandonments, (5) a $28.6 million loss on extinguishment of debt, (6) a $1.3 million loss on disposition of assets, net, (7) $11.4 million of other settlements, (8) a $19.6 million gain related to the disposition of non-core assets included in discontinued operations and (9) a $21.9 million benefit for a change in state statutory effective income tax rate. Excluding these items and their tax effects, the 2013 adjusted net income (non-GAAP) was $368.7 million, or $3.51 per diluted share. Excluding similar non-cash items and their tax impact, adjusted net income (non-GAAP) for 2012 was $388.9 million, or $3.74 per diluted share. For a description and a reconciliation of net income (GAAP) to adjusted net income (non-GAAP), please see “Supplemental Non-GAAP Financial Measures” below.
EBITDAX was $1,685.6 million in 2013, an increase of 14% from $1,475.6 million in 2012. For a description and a reconciliation of net income (GAAP) to EBITDAX (non-GAAP), please see “Supplemental Non-GAAP Financial Measures” below.
Oil and natural gas sales from continuing operations for 2013 increased 27% when compared to 2012. This increase was attributable to a 20% increase in production from continuing operations in 2013 compared to 2012 and a 4% increase in the Company’s unhedged realized oil price in 2013 compared to 2012.
Oil and natural gas production expense from continuing operations for 2013, including oil and natural gas taxes, totaled $455.4 million, or $13.54 per barrel of oil equivalent (“Boe”), a 10% increase per Boe from 2012. This increase was due primarily to higher lease operating expenses (“LOE”) and workover costs, which averaged $7.85 per Boe in 2013 as compared to $6.90 per Boe in 2012. The increase in LOE and workover costs per Boe during 2013 was primarily due to increased activity in higher-cost areas with developing infrastructure, like the Delaware Basin.
Depreciation, depletion and amortization expense (“DD&A”) from continuing operations for 2013 totaled $772.6 million, or $22.97 per Boe, a 12% increase per Boe from 2012.
General and administrative expense (“G&A”) from continuing operations for 2013 totaled $169.8 million, or $5.04 per Boe, as compared to $133.8 million, or $4.79 per Boe, in 2012. Cash G&A expenses for 2013 totaled $134.7 million and stock-based compensation (non-cash) totaled $35.1 million. The increase in per Boe expense for 2013 over 2012 was primarily due to a 27% increase in absolute G&A expenses reflecting increased staffing across the Company, and was partially offset by a 20% increase in production from continuing operations.
The Company’s cash flow from operating activities (GAAP) was $1,362.0 million for 2013, as compared to $1,237.5 million for 2012, an increase of 10%. Adjusted cash flows (non-GAAP), which are cash flows from operating activities (GAAP) adjusted for settlements on derivatives not designated as hedges, were $1,329.7 million for 2013, as compared to $1,261.0 million for 2012, an increase of 5%. For a description of the use of adjusted cash flows (non-GAAP) and for a reconciliation of cash flows from operating activities (GAAP) to adjusted cash flows (non-GAAP), please see “Supplemental Non-GAAP Financial Measures” below.
For 2013, the Company commenced drilling or participated in a total of 633 gross wells (465 operated, 44% horizontal), 4 of which were unsuccessful, and completed 675 wells as producers. The Company is operating 34 drilling rigs; 2 of these rigs are drilling Yeso wells in the New Mexico Shelf, 11 are drilling in the Texas Permian and 21 are drilling in the Delaware Basin. Of the 34 operated rigs, the Company is currently running 30 horizontal drilling rigs, including 21 in the Delaware Basin, 7 in the Texas Permian and 2 in the New Mexico Shelf.
Year-End 2013 Location Update
At year-end 2013, the Company had identified approximately 22,000 drilling locations across its 1.2 million gross (605,000 net) acreage position. The resource potential associated with these 22,000 drilling locations including what the Company has identified as proved is approximately six times the Company's year-end 2013 proved reserves of 503 MMBoe.
New Mexico Shelf
At year-end 2013, the Company had identified approximately 2,700 drilling locations in the New Mexico Shelf. Of these 2,700 drilling locations, approximately 1,100 locations target the Yeso formation vertically and approximately 1,250 locations target the Yeso formation horizontally. As previously disclosed, the New Mexico Shelf experienced natural gas processing issues during 2013, which the Company estimates to have reduced full-year volumes by over 500 MBoe. Recently, the Company has seen continued improvement in line pressures and is monitoring multiple projects designed to further improve processing and takeaway capacity that are currently being developed and expected to be operational by mid-2014.
At year-end 2013, the Company had identified approximately 10,600 drilling locations in the Delaware Basin. In the northern Delaware Basin, these locations include approximately 6,000 locations targeting the Bone Spring sands, approximately 1,500 targeting the Avalon shale, approximately 1,400 targeting the Wolfcamp, and approximately 850 targeting the Brushy Canyon. In the southern Delaware Basin, these locations include approximately 800 Wolfcamp and 2nd Bone Spring sands locations.
Of the 63 wells drilled in the Delaware Basin in the fourth quarter of 2013, 45 were Bone Spring sands wells, 12 were Wolfcamp shale wells, 5 were Brushy Canyon wells, and 1 was an Avalon shale well. The Company’s net production in the fourth quarter of 2013 from horizontal Delaware Basin wells averaged approximately 35.9 MBoe per day, an increase of 70% over the fourth quarter of 2012 and an increase of 7% over the third quarter of 2013.
In the northern Delaware Basin, 26 new wells had at least 30 days of production by the end of the fourth quarter of 2013, with an average 30-day rate of 749 barrels of oil equivalent per day (“Boepd”) (77% oil) and an average 24-hour peak rate of 1,121 Boepd from an average lateral length of 4,327 feet. In the southern Delaware Basin, 21 wells had at least 30 days of production by the end of the fourth quarter of 2013, with an average 30-day rate of 984 Boepd (80% oil) and an average 24-hour peak rate of 1,303 Boepd from an average lateral length of 4,378 feet.
At year-end 2013, the Company had identified approximately 8,500 drilling locations. Of these 8,500 drilling locations, approximately 1,800 target the vertical Wolfberry play on 40-acre spacing, approximately 2,500 target the vertical Wolfberry play on 20-acre spacing, approximately 1,400 target the vertical shallow Wolfcamp and approximately 2,500 target the horizontal Spraberry and Wolfcamp.
In the Texas Permian, 12 horizontal wells had at least 30 days of production by the end of the fourth quarter of 2013, with an average 30-day rate of 614 Boepd (75% oil) and an average 24-hour peak rate of 915 Boepd (78% oil) from an average lateral length of 4,415 feet.
The Company maintains an active crude oil and natural gas hedging program and has continued to add to its derivative positions. Please see the “Derivatives Information” table at the end of this press release for more detailed information about the Company’s current derivative positions.
At December 31, 2013, the Company had borrowings outstanding under its credit facility of $250.0 million, and the availability under the credit facility was approximately $2.2 billion.
The Company’s 2014 production guidance range is 18 - 22% growth over 2013 volumes. For the first quarter of 2014, the Company expects production to average between 98 - 101 MBoe per day. Additionally, the Company is forecasting first quarter of 2014 LOE to be above the full year guidance range of $7.50 - $8.00 per Boe due, in part, to increased costs associated with restoring production from the winter weather in the fourth quarter of 2013. However, the Company expects full year 2014 lease operating expense to fall within the original guidance range of $7.50 - $8.00 per Boe.
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