Concho Resources Inc. Reports Fourth Quarter 2013 and Year End Financial and Operating Results

MIDLAND, Texas--()--Concho Resources Inc. (NYSE: CXO) (“Concho” or the “Company”) today reported financial and operating results for the three months and year ended December 31, 2013. Highlights for the year ended December 31, 2013 include:

  • Production of 33.6 million barrels of oil equivalent (“MMBoe”) for 2013, a 20% increase over 2012 production from continuing operations
  • Net income of $251.0 million, or $2.39 per diluted share, for 2013, as compared to net income of $431.7 million, or $4.15 per diluted share, in 2012
  • Adjusted net income1 (non-GAAP) of $368.7 million, or $3.51 per diluted share, for 2013, as compared to $388.9 million, or $3.74 per diluted share, for 2012
  • EBITDAX2 (non-GAAP) of $1,685.6 million for 2013, a 14% increase over 2012

1 Adjusted net income (non-GAAP) is comparable to securities analyst estimates. For an explanation of how we calculate adjusted net income (non-GAAP) and a reconciliation of net income (GAAP) to adjusted net income (non-GAAP), please see "Supplemental Non-GAAP Financial Measures" below.

2 For an explanation of how we calculate and use EBITDAX (non-GAAP) and a reconciliation of net income (GAAP) to EBITDAX (non-GAAP), please see "Supplemental Non-GAAP Financial Measures" below.

Financial Results

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.

Operations

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 table below summarizes the Company’s gross drilling activities by core area for the fourth quarter and full year 2013:

    Total Wells     Operated Wells     Completed Wells1
4Q 2013   FY 2013 4Q 2013   FY 2013 4Q 2013   FY 2013
New Mexico Shelf 26 197 6 83 34 223
Delaware Basin 63 202 49 149 50 192
Texas Permian 34 234 33 233 38 260
Total 123 633 88 465 122 675

1 Excludes 4 wells that were unsuccessful in 2013.

Currently, 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.

Delaware Basin

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.

Texas Permian

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.

Derivative Update

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.

Credit Facility

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.

Guidance

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.

Conference Call and Presentation Information

The Company will host a conference call with an accompanying presentation on Thursday, February 20, 2014, at 9:00 a.m. CST to further discuss information regarding 2013 reserves, inventory and fourth quarter and full-year 2013 financial and operating results. Interested parties may listen to the conference call via the Company’s website at www.concho.com or by dialing (877) 415-3186 (passcode: 28809385). The presentation is also available on the Company’s website. To access the presentation, visit www.concho.com and select “Investor Relations,” then “Presentations.”

A replay of the conference call will be available on the Company’s website or by dialing (888) 286-8010 (passcode: 17690036).

About Concho Resources Inc.

Concho Resources Inc. is an independent oil and natural gas company engaged in the acquisition, development and exploration of oil and natural gas properties. The Company's operations are focused in the Permian Basin of Southeast New Mexico and West Texas. For more information, visit Concho’s website at www.concho.com.

Forward-Looking Statements and Cautionary Statements

The foregoing contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this press release specifically include statements, estimates and projections regarding the Company's future financial position, operations, performance, production growth, returns, divestitures, capital expenditure budget, the proceeds of the sale of the non-core properties, oil and natural gas reserves, number of identified drilling locations, drilling program, derivative activities, costs and other guidance. These statements are based on certain assumptions made by the Company based on management's experience, expectations and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Forward-looking statements are not guarantees of performance. Although the Company believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include the factors discussed or referenced in the "Risk Factors" section of the Company's most recent Form 10-K and 10-Q filings and risks relating to declines in the prices we receive for our oil and natural gas; uncertainties about the estimated quantities of reserves; risks related to the integration of acquired assets; the effects of government regulation, permitting and other legal requirements, including new legislation or regulation of hydraulic fracturing; drilling and operating risks; the adequacy of our capital resources and liquidity; risks related to the concentration of our operations in the Permian Basin; the results of our hedging program; weather; litigation; shortages of oilfield equipment, services and qualified personnel and increases in costs for such equipment, services and personnel; uncertainties about our ability to replace reserves and economically develop our current reserves; competition in the oil and natural gas industry; and other important factors that could cause actual results to differ materially from those projected.

We may use the terms “unproved reserves,” “resource potential,” “EUR” per well and “upside potential” to describe estimates of potentially recoverable hydrocarbons that the U.S. Securities and Exchange Commission (“SEC”) rules prohibit from being included in filings with the SEC. These are based on analogy to the Company’s existing models applied to additional acres, additional zones and tighter spacing and are the Company’s internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. These quantities may not constitute “reserves” within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or SEC rules. EUR estimates, resource potential and drilling locations have not been fully risked by Company management and are inherently more speculative than proved reserves estimates. Actual locations drilled and quantities that may be ultimately recovered from the Company’s interests could differ substantially. There is no commitment by the Company to drill all of the drilling locations which have been attributed to these quantities. Factors affecting ultimate recovery include the scope of our ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors; and actual drilling results, including geological and mechanical factors affecting recovery rates. Estimates of unproved reserves, resource potential, per well EUR and upside potential may change significantly as development of the Company’s oil and natural gas assets provide additional data. Our production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases.

Any forward-looking statement speaks only as of the date on which such statement is made, and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

 
 
Concho Resources Inc.
Consolidated Balance Sheets
Unaudited
 
       
December 31,
(in thousands, except share and per share amounts)       2013         2012  
Assets
Current assets:
Cash and cash equivalents $ 21 $ 2,880
Accounts receivable, net of allowance for doubtful accounts:
Oil and natural gas 223,790 198,053
Joint operations and other 247,945 202,738
Derivative instruments 590 35,942
Deferred income taxes 30,069 -
Prepaid costs and other   18,460     19,269  
Total current assets   520,875     458,882  
Property and equipment:
Oil and natural gas properties, successful efforts method 11,215,373 9,455,599
Accumulated depletion and depreciation   (2,384,108 )   (1,565,316 )
Total oil and natural gas properties, net 8,831,265 7,890,283
Other property and equipment, net   114,783     103,141  
Total property and equipment, net   8,946,048     7,993,424  
Deferred loan costs, net 73,048 77,609
Intangible asset - operating rights, net 28,615 30,076
Inventory 19,682 20,611
Noncurrent derivative instruments 966 2,769
Other assets   1,930     6,066  
Total assets $ 9,591,164   $ 8,589,437  
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable:
Trade $ 13,936 $ 31,144
Related parties - 185
Bank overdrafts 36,718 24,275
Revenue payable 177,617 162,073
Accrued and prepaid drilling costs 318,296 351,919
Derivative instruments 53,701 1,584
Deferred income taxes - 8,566
Other current liabilities   156,600     160,340  
Total current liabilities   756,868     740,086  
Long-term debt 3,630,421 3,101,103
Deferred income taxes 1,334,653 1,186,621
Noncurrent derivative instruments 14,088 12,049
Asset retirement obligations and other long-term liabilities 97,185 83,382
Commitments and contingencies
Stockholders’ equity:
Common stock, $0.001 par value; 300,000,000 authorized; 105,222,765 and 104,668,427
shares issued at December 31, 2013 and 2012, respectively 105 105
Additional paid-in capital 2,027,162 1,982,714
Retained earnings 1,741,566 1,490,563

Treasury stock, at cost; 127,305 and 86,861 shares at December 31, 2013 and 2012, respectively

  (10,884 )   (7,186 )
Total stockholders’ equity   3,757,949     3,466,196  
Total liabilities and stockholders’ equity $ 9,591,164   $ 8,589,437  
 

 
 
Concho Resources Inc.
Consolidated Statements of Operations
Unaudited
 
               
Three Months Ended Years Ended
December 31, December 31,
(in thousands, except per share amounts)       2013         2012         2013         2012  
 
Operating revenues:
Oil sales $ 525,546 $ 383,494 $ 1,938,433 $ 1,482,998
Natural gas sales   106,540     94,032     381,486     336,816  
Total operating revenues   632,086     477,526     2,319,919     1,819,814  
Operating costs and expenses:
Oil and natural gas production 127,141 92,102 455,436 343,743
Exploration and abandonments 71,752 12,505 109,549 39,840
Depreciation, depletion and amortization 214,833 166,453 772,608 575,128
Accretion of discount on asset retirement obligations 1,637 1,361 6,047 4,187
Impairments of long-lived assets - - 65,375 -
General and administrative (including non-cash stock-based compensation of
$9,800 and $8,438 for the three months ended December 31, 2013 and
2012, respectively, and $35,078 and $29,872 for the years ended
December 31, 2013 and 2012, respectively) 44,695 37,802 169,815 133,796
(Gain) loss on derivatives not designated as hedges   (33,651 )   (17,901 )   123,652     (127,443 )
Total operating costs and expenses   426,407     292,322     1,702,482     969,251  
Income from operations   205,679     185,204     617,437     850,563  
Other income (expense):
Interest expense (56,401 ) (53,632 ) (218,581 ) (182,705 )
Loss on extinguishment of debt - - (28,616 ) -
Other, net   (11,275 )   (3,670 )   (13,081 )   (8,587 )
Total other expense   (67,676 )   (57,302 )   (260,278 )   (191,292 )
Income from continuing operations before income taxes 138,003 127,902 357,159 659,271
Income tax expense   (32,214 )   (46,714 )   (118,237 )   (251,041 )
Income from continuing operations 105,789 81,188 238,922 408,230
Income (loss) from discontinued operations, net of tax   -     (5,901 )   12,081     23,459  
Net income $ 105,789   $ 75,287   $ 251,003   $ 431,689  
Basic earnings per share:
Income from continuing operations $ 1.01 $ 0.78 $ 2.28 $ 3.96
Income (loss) from discontinued operations, net of tax   -     (0.05 )   0.11     0.22  
Net income $ 1.01   $ 0.73   $ 2.39   $ 4.18  
Diluted earnings per share:
Income from continuing operations $ 1.01 $ 0.78 $ 2.28 $ 3.93
Income (loss) from discontinued operations, net of tax   -     (0.06 )   0.11     0.22  
Net income $ 1.01   $ 0.72   $ 2.39   $ 4.15  
 

 
 
Concho Resources Inc.
Consolidated Statements of Cash Flows
Unaudited
 
   
Years Ended December 31,
(in thousands)       2013         2012  
CASH FLOWS FROM OPERATING ACTIVITIES:    
Net income $ 251,003 $ 431,689
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization 772,608 575,128
Accretion of discount on asset retirement obligations 6,047 4,187
Impairments of long-lived assets 65,375 -
Exploration and abandonments, including dry holes 80,714 19,913
Non-cash compensation expense 35,078 29,872
Deferred income taxes 102,427 241,819
Loss on disposition of assets, net 1,268 372
(Gain) loss on derivatives not designated as hedges 123,652 (127,443 )
Discontinued operations (12,250 ) 49,011
Other non-cash items 19,720 12,420
Changes in operating assets and liabilities, net of acquisitions and dispositions:
Accounts receivable (40,009 ) (23,091 )
Prepaid costs and other 4,945 (8,200 )
Inventory 509 (1,587 )
Accounts payable (18,469 ) 4,165
Revenue payable 28,593 16,012
Other current liabilities   (59,191 )   13,211  
Net cash provided by operating activities   1,362,020     1,237,478  
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures on oil and natural gas properties (1,850,992 ) (2,717,283 )
Additions to other property and equipment (28,678 ) (56,588 )
Proceeds from the disposition of assets 15,217 492,497
Funds held in escrow - 17,394
Settlements received from (paid on) derivatives not designated as hedges   (32,341 )   23,536  
Net cash used in investing activities   (1,896,794 )   (2,240,444 )
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of debt 3,257,575 4,262,000
Payments of debt (2,729,700 ) (3,241,500 )
Exercise of stock options 3,223 8,123
Excess tax benefit from stock-based compensation 6,147 18,963
Payments for loan costs (14,075 ) (23,926 )
Purchase of treasury stock (3,698 ) (3,190 )
Bank overdrafts   12,443     (14,966 )
Net cash provided by financing activities   531,915     1,005,504  
Net increase (decrease) in cash and cash equivalents (2,859 ) 2,538
Cash and cash equivalents at beginning of period   2,880     342  
Cash and cash equivalents at end of period $ 21   $ 2,880  
SUPPLEMENTAL CASH FLOWS:
Cash paid for interest and fees $ 200,961 $ 158,715
Cash paid for income taxes $ 21,376 $ 19,674
 
 
 

Concho Resources Inc.
Summary Production and Price Data
Unaudited

The following table sets forth summary information from our continuing and discontinued operations concerning our production and operating data for the periods indicated:

 
          Three Months Ended     Years Ended
December 31, December 31,
              2013     2012     2013     2012
       
Production and operating data from continuing and discontinued operations:
Net production volumes:
Oil (MBbl) 5,750 4,950 21,126 18,003
Natural gas (MMcf) 19,048 19,621 75,054 70,591
Total (MBoe) 8,925 8,220 33,635 29,768
 
Average daily production volumes:
Oil (Bbl) 62,500 53,804 57,879 49,189
Natural gas (Mcf) 207,043 213,272 205,627 192,872
Total (Boe) 97,007 89,350 92,150 81,334
 
Average prices:
Oil, without derivatives (Bbl) $ 91.40 $ 81.28 $ 91.76 $ 88.01
Oil, with derivatives (Bbl) (a) $ 91.56 $ 87.50 $ 89.79 $ 89.25
Natural gas, without derivatives (Mcf) $ 5.59 $ 5.06 $ 5.08 $ 5.03
Natural gas, with derivatives (Mcf) (a) $ 5.83 $ 5.07 $ 5.21 $ 5.05
Total, without derivatives (Boe) $ 70.82 $ 61.02 $ 68.97 $ 65.16
Total, with derivatives (Boe) (a) $ 71.42 $ 64.80 $ 68.01 $ 65.95
 
Operating costs and expenses per Boe:
Lease operating expenses and workover costs $ 8.57 $ 7.17 $ 7.85 $ 7.27
Oil and natural gas taxes $ 5.68 $ 5.19 $ 5.69 $ 5.43
Depreciation, depletion and amortization $ 24.07 $ 20.73 $ 22.97 $ 20.34
General and administrative $ 5.01 $ 4.51 $ 5.04 $ 4.40
                                 
 
(a) Includes the effect of cash settlements received from (paid on) commodity derivatives not designated as hedges:
                             
 
Three Months Ended Years Ended
December 31, December 31,
(in thousands)     2013     2012     2013     2012
 
Cash receipts from (payments on) derivatives not designated as hedges:
Oil derivatives $ 912 $ 30,785 $ (41,616 ) $ 22,411
Natural gas derivatives   4,431   236   9,275     1,125
Total $ 5,343 $ 31,021 $ (32,341 ) $ 23,536
                             
 
The presentation of average prices with derivatives is a non-GAAP measure as a result of including the cash receipts from (payments on) commodity derivatives that are presented in our statements of cash flows. This presentation of average prices with derivatives is a means by which to reflect the actual cash performance of our commodity derivatives for the respective periods and presents oil and natural gas prices with derivatives in a manner consistent with the presentation generally used by the investment community.
 
 

The following table sets forth summary information from our continuing operations concerning production and operating data for the periods indicated:

 
          Three Months Ended     Years Ended
December 31, December 31,
              2013     2012     2013     2012
       
Production and operating data from continuing operations:
Net production volumes:
Oil (MBbl) 5,750 4,718 21,126 16,859
Natural gas (MMcf) 19,048 18,462 75,054 66,613
Total (MBoe) 8,925 7,795 33,635 27,961
 
Average daily production volumes:
Oil (Bbl) 62,500 51,283 57,879 46,063
Natural gas (Mcf) 207,043 200,674 205,627 182,003
Total (Boe) 97,007 84,728 92,150 76,397
 
Average prices:
Oil, without derivatives (Bbl) $ 91.40 $ 81.28 $ 91.76 $ 87.96
Oil, with derivatives (Bbl) (a) $ 91.56 $ 87.81 $ 89.79 $ 89.29
Natural gas, without derivatives (Mcf) $ 5.59 $ 5.09 $ 5.08 $ 5.06
Natural gas, with derivatives (Mcf) (a) $ 5.83 $ 5.11 $ 5.21 $ 5.07
Total, without derivatives (Boe) $ 70.82 $ 61.26 $ 68.97 $ 65.08
Total, with derivatives (Boe) (a) $ 71.42 $ 65.24 $ 68.01 $ 65.93
 
Operating costs and expenses per Boe:
Lease operating expenses and workover costs $ 8.57 $ 6.64 $ 7.85 $ 6.90
Oil and natural gas taxes $ 5.68 $ 5.17 $ 5.69 $ 5.39
Depreciation, depletion and amortization $ 24.07 $ 21.35 $ 22.97 $ 20.56
General and administrative $ 5.01 $ 4.85 $ 5.04 $ 4.79
                                 
 
(a) Includes the effect of cash settlements received from (paid on) commodity derivatives not designated as hedges:
                             
 
Three Months Ended Years Ended
December 31, December 31,
(in thousands)     2013     2012     2013     2012
 
Cash receipts from (payments on) derivatives not designated as hedges:
Oil derivatives $ 912 $ 30,785 $ (41,616 ) $ 22,411
Natural gas derivatives   4,431   236   9,275     1,125
Total $ 5,343 $ 31,021 $ (32,341 ) $ 23,536
                             
 
The presentation of average prices with derivatives is a non-GAAP measure as a result of including the cash receipts from (payments on) commodity derivatives that are presented in our statements of cash flows. This presentation of average prices with derivatives is a means by which to reflect the actual cash performance of our commodity derivatives for the respective periods and presents oil and natural gas prices with derivatives in a manner consistent with the presentation generally used by the investment community.
 
 

Concho Resources Inc.
Supplemental Non-GAAP Financial Measures
Unaudited

The following tables provide information that the Company believes may be useful to investors who follow the practice of some industry analysts who adjust reported company net income and cash flows from operating activities to exclude certain non-cash and unusual items.

Adjusted Net Income

The following table provides a reconciliation of net income (GAAP) to adjusted net income (non-GAAP) for the periods indicated:

 
    Three Months Ended     Years Ended
December 31, December 31,
(in thousands, except per share amounts)       2013         2012         2013         2012  
       
Net income - as reported $ 105,789 $ 75,287 $ 251,003 $ 431,689
 
Adjustments for certain non-cash and unusual items:
(Gain) loss on derivatives not designated as hedges (33,651 ) (17,901 ) 123,652 (127,443 )
Cash receipts from (payments on) derivatives not designated as hedges 5,343 31,021 (32,341 ) 23,536
Impairments of long-lived assets - - 65,375 -
Leasehold abandonments 35,930 3,161 49,758 12,395
Loss on extinguishment of debt - - 28,616 -
(Gain) loss on disposition of assets, net (449 ) 87 1,268 372
Other 11,393 3,242 11,393 3,242
Discontinued operations:
(Gain) loss on disposition of assets - 18,704 (19,599 ) 18,704
Tax impact (a) (7,204 ) (13,985 ) (88,511 ) 26,363
Change in state statutory effective income tax rate   (21,876 )   -     (21,876 )   -  
Adjusted net income $ 95,275   $ 99,616   $ 368,738   $ 388,858  
 
Adjusted earnings per share:
Basic $ 0.91 $ 0.96 $ 3.52 $ 3.77
Diluted $ 0.91 $ 0.96 $ 3.51 $ 3.74
 
Effective tax rates 38.8 % 36.5 % 38.8 % 38.1 %
                         
 
(a) The tax impact is computed utilizing the Company's adjusted statutory effective federal and state income tax rates shown in the table above.
 
 
 

Adjusted Cash Flows

The following table provides a reconciliation of cash flows from operating activities (GAAP) to adjusted cash flows (non-GAAP) for the periods indicated:

       
Years Ended December 31,
(in thousands)     2013     2012
 
Cash flows from operating activities $ 1,362,020 $ 1,237,478
Settlements received from (paid on) derivatives not designated as hedges (a)   (32,341 )   23,536
Adjusted cash flows $ 1,329,679   $ 1,261,014
             
 
(a) Amounts are presented in cash flows from investing activities for GAAP purposes.
 
 
 

EBITDAX

EBITDAX (as defined below) is presented herein, and reconciled from the generally accepted accounting principles (“GAAP”) measure of net income because of its wide acceptance by the investment community as a financial indicator of a company's ability to internally fund exploration and development activities.

The Company defines EBITDAX as net income, plus (1) exploration and abandonments expense, (2) depreciation, depletion and amortization expense, (3) accretion expense, (4) impairments of long-lived assets (5) non-cash stock-based compensation expense, (6) (gain) loss on derivatives not designated as hedges, (7) cash receipts from (payments on) derivatives not designated as hedges, (8) (gain) loss on disposition of assets, net, (9) interest expense, (10) loss on extinguishment of debt, (11) federal and state income taxes on continuing operations and (12) similar items listed above that are presented in discontinued operations. EBITDAX is not a measure of net income or cash flows as determined by GAAP.

The Company’s EBITDAX measure (which includes continuing and discontinued operations) provides additional information which may be used to better understand the Company’s operations. EBITDAX is one of several metrics that the Company uses as a supplemental financial measurement in the evaluation of its business and should not be considered as an alternative to, or more meaningful than, net income, as an indicator of operating performance. Certain items excluded from EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic cost of depreciable assets, none of which are components of EBITDAX. EBITDAX, as used by the Company, may not be comparable to similarly titled measures reported by other companies. The Company believes that EBITDAX is a widely followed measure of operating performance and is one of many metrics used by the Company’s management team, and by other users, of the Company’s consolidated financial statements. For example, EBITDAX can be used to assess the Company’s operating performance and return on capital in comparison to other independent exploration and production companies without regard to financial or capital structure, and to assess the financial performance of the Company’s assets and the Company without regard to capital structure or historical cost basis.

The following table provides a reconciliation of net income to EBITDAX for the periods indicated:

 
               
Three Months Ended Years Ended
December 31, December 31,
(in thousands)       2013         2012         2013         2012  
 
Net income $ 105,789 $ 75,287 $ 251,003 $ 431,689
Exploration and abandonments 71,752 12,505 109,549 39,840
Depreciation, depletion and amortization 214,833 166,453 772,608 575,128
Accretion of discount on asset retirement obligations 1,637 1,361 6,047 4,187
Impairments of long-lived assets - - 65,375 -
Non-cash stock-based compensation 9,800 8,438 35,078 29,872
(Gain) loss on derivatives not designated as hedges (33,651 ) (17,901 ) 123,652 (127,443 )
Cash receipts from (payments on) derivatives not designated as hedges 5,343 31,021 (32,341 ) 23,536
(Gain) loss on disposition of assets, net (449 ) 87 1,268 372
Interest expense 56,401 53,632 218,581 182,705
Loss on extinguishment of debt - - 28,616 -
Income tax expense from continuing operations 32,214 46,714 118,237 251,041
Discontinued operations   -     21,299     (12,081 )   64,701  
EBITDAX $ 463,669   $ 398,896   $ 1,685,592   $ 1,475,628  
 

 
 
Concho Resources Inc.
Costs Incurred
Unaudited
 

The table below provides the costs incurred for the periods indicated:

 

Costs incurred for oil and natural gas producing activities (a)

 
      Three Months Ended     Years Ended
December 31, December 31,
(in thousands)     2013     2012     2013     2012
       
Property acquisition costs:
Proved $ 9,123 $ 2,063 $ 11,499 $ 857,836
Unproved 26,706 29,932 85,538 441,042
Exploration 250,767 214,109 1,029,793 781,174
Development   145,424   166,665   738,430   741,206
Total costs incurred for oil and natural gas properties $ 432,020 $ 412,769 $ 1,865,260 $ 2,821,258
                             
 
(a) The costs incurred for oil and natural gas producing activities includes the following amounts of asset retirement obligations:
                           
 
Three Months Ended Years Ended
December 31, December 31,
(in thousands)     2013     2012     2013     2012
 
Exploration costs $ 583 $ 159 $ 2,672 $ 2,611
Development costs   304   7,234   9,467   15,536
Total asset retirement obligations $ 887 $ 7,393 $ 12,139 $ 18,147
 

 

 

Concho Resources Inc.
Derivatives Information
Unaudited
 

The tables below provide data associated with the Company’s derivatives at February 19, 2014 for the periods indicated:

 
    2014
First Quarter     Second Quarter     Third Quarter     Fourth Quarter     Total
 
Oil Swaps: (a)
Volume (Bbl) 5,075,000 4,544,000 4,116,000 3,833,000 17,568,000
Price (Bbl) $ 93.65 $ 92.69 $ 91.23 $ 91.09 $ 92.27
 
Oil Basis Swaps: (b)
Volume (Bbl) 2,790,000 3,458,000 3,956,000 3,680,000 13,884,000
Price (Bbl) $ (0.46 ) $ (0.72 ) $ (0.99 ) $ (0.92 ) $ (0.80 )
 
Natural Gas Swaps: (c)
Volume (MMBtu) 3,812,000 3,001,000 2,300,000 1,777,000 10,890,000
Price (MMBtu) $ 4.19 $ 4.18 $ 4.19 $ 4.19 $ 4.19
 
Natural Gas Collars: (d)
Volume (MMBtu) 5,400,000 5,460,000 5,520,000 5,520,000 21,900,000
Ceiling Price (MMBtu) $ 4.40 $ 4.40 $ 4.40 $ 4.40 $ 4.40
Floor Price (MMBtu) $ 3.85 $ 3.85 $ 3.85 $ 3.85 $ 3.85
                                 
 
                                 
 
  2015     2016     2017  
Oil Swaps: (a)
Volume (Bbl) 12,812,000 429,000 168,000
Price (Bbl) $ 86.86 $ 88.31 $ 87.00
 
Natural Gas Swaps: (c)
Volume (MMBtu) 20,075,000 - -
Price (MMBtu) $ 4.15 $ - $ -
                                 
 
(a) The index prices for the oil contracts are based on the NYMEX – West Texas Intermediate (“WTI”) monthly average futures price.
(b) The basis differential price is between the Midland – WTI and the Cushing – WTI.
(c) The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price.
(d) The index prices for the natural gas collars are based on the El Paso Permian delivery point.

Contacts

Concho Resources Inc.
Price Moncrief, 432-683-7443
Vice President of Capital Markets and Strategy

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Contacts

Concho Resources Inc.
Price Moncrief, 432-683-7443
Vice President of Capital Markets and Strategy