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| CWEI > SEC Filings for CWEI > Form 10-K on 5-Mar-2013 | All Recent SEC Filings |
5-Mar-2013
Annual Report
The following discussion is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations and cash flows and should be read in conjunction with our consolidated financial statements and notes thereto included elsewhere in this Form 10-K.
Overview
Throughout 2012, we continued our developmental drilling in two primary oil-prone regions, the Permian Basin and Giddings Area, where we have a significant inventory of developmental drilling opportunities. We currently have two of our drilling rigs working in Reeves County, Texas drilling Wolfbone wells. We spent approximately $273.6 million in the Wolfbone area in Reeves County in 2012 on drilling, completion and leasing activities and currently plan to spend approximately $87.2 million in this area in 2013. We currently have one of our drilling rigs working in Andrews County, Texas drilling Wolfberry wells. We spent approximately $59.6 million related primarily to drilling and completing Wolfberry wells in Andrews County in 2012 and currently plan to spend approximately $20 million in this area in 2013.
We are continuing to exploit our extensive acreage position in the Giddings Area of East Central Texas. While most of our drilling activities have been directed toward infill drilling of horizontal wells in the Austin Chalk formation, this area is also known for its reserve potential from other formations such as the Eagle Ford Shale, Buda, Georgetown, Cotton Valley, Deep Bossier and Taylor formations. In 2012, we spent approximately $40.2 million on Austin Chalk/Eagle Ford Shale drilling and leasing activities. Since July 2011, we have drilled six horizontal Eagle Ford Shale wells: the Hosek Unit #1, the Ortmann Unit #1 and the Kutac Unit #1 in Wilson County, the Balcar Unit #1 in Lee County, the Scasta Unit #2 in Brazos County and the Sarah Ferrara E Unit #1 in Robertson County. We are currently working one of our drilling rigs in this area to drill horizontal wells in the Eagle Ford Shale and currently plan to spend approximately $71.3 million on drilling and completion costs and $20 million on leasing activities in 2013.
Over the past two years, we have invested more than $800 million in the Permian Basin and the Giddings Area. We outspent our cash flow by approximately $460 million, and increased our total debt by $425 million from December 31, 2010 to December 31, 2012. During 2013, we plan to take steps to reduce debt and achieve a sustainable balance between future capital expenditures and capital resources by reducing capital spending from $436.8 million in 2012 to $225.6 million in 2013, offering our Andrews County Wolfberry assets for sale and seeking a joint venture partner in Reeves County.
Key Factors to Consider
The following summarizes the key factors considered by management in the review of our financial condition and operating performance for 2012 and the outlook for 2013.
• Our oil and gas sales, excluding amortized deferred revenues, decreased $10.4 million, or 3%, from 2011. Price variances accounted for a decrease of $25.6 million and production variances accounted for a $15.2 million increase. Oil and gas sales in 2012 also includes $8.3 million of amortized deferred revenue attributable to the VPP granted effective March 1, 2012 to finance the merger consideration payable in connection with the mergers of each of 24 limited partnerships of which SWR was the general partner into SWR ("SWR Mergers").
• Our oil production increased 3% compared to 2011 while gas production declined 6%. Our combined oil and gas production for 2012 increased 3% on a BOE basis compared to 2011. The increase in oil production and the decline in gas production are indicative of our current emphasis on the development of oil reserves in the Permian Basin.
• Production costs increased 24% from $101.1 million in 2011 to $125 million in 2012 due to a combination of an increase in the number of producing wells, higher costs of field services, including salt water disposal costs, and higher property taxes on Texas properties resulting from rising appraisal values.
• We recorded a $14.4 million net gain on derivatives in 2012, consisting of a $17.8 million non-cash unrealized gain for changes in mark-to-market valuations and a $3.4 million realized loss on settled contracts. For fiscal 2011, we recorded a $47 million net gain on derivatives, consisting of a $4.5 million non-cash unrealized gain for changes in mark-to-market valuations and a $42.5 million realized gain on settled contracts. Cash settlements in 2011 included $50 million from the early termination of contracts covering oil production for 2012 and 2013. Since we do not presently designate our derivatives as cash flow hedges under applicable accounting standards, we recognize the full effect of changing prices on mark-to-market valuations as a current charge or credit to our results of operations.
• Depreciation, depletion and amortization expense increased 36% to $142.7 million in 2012 versus $104.9 million in 2011 due primarily to a 27% increase in the average depletion rate per BOE of production. Most of the increase in depletion rate related to downward revisions in proved reserves in the Company's Andrews County Wolfberry play.
• Interest expense increased to $38.7 million in 2012 from $32.9 million in 2011 due primarily to the increase in our revolving credit facility from an average daily principal balance of $113.4 million in 2011 to $349.1 million in 2012.
• General and administrative ("G&A") expenses for 2012 were $30.5 million compared to $41.6 million in 2011. Non-cash employee compensation from incentive compensation plans accounted for a credit to expense of $404,000 in 2012 versus $12.9 million expense in 2011. G&A expenses, excluding non-cash employee compensation expense, increased to $30.9 million in 2012 versus $28.7 million in 2011. The 2012 period included $2 million of non-recurring donations to charitable and 527 organizations.
• Our estimated proved oil and gas reserves at December 31, 2012 increased 17% to 75,357 MBOE from 64,349 MBOE at December 31, 2011. We replaced 365% of our oil and gas production in 2012 through extensions and discoveries of 20,443 MBOE , had purchases of minerals-in-place of 3,504 MBOE, had downward net revisions of 6,615 MBOE, and had sales of minerals-in-place of 725 MBOE (see Part I "Item 2 - Properties - Reserves").
Proved Oil and Gas Reserves
The following table summarizes changes in our estimated proved reserves during
2012.
Proved
Reserves
(MBOE)
As of December 31, 2011 64,349
Extensions and discoveries 20,443
Purchases of minerals-in-place 3,504
Revisions (6,615 )
Sales of minerals-in-place (725 )
Production (5,599 )
As of December 31, 2012 75,357
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Extensions and discoveries. Extensions and discoveries in 2012 added 20,443 MBOE of proved reserves, replacing 365% of our 2012 production. These additions resulted primarily from our Reeves County and Andrews County drilling programs in the Permian Basin. Of the total reserve additions, proved developed reserves accounted for 5,975 MBOE, while the remaining 14,468 MBOE were proved undeveloped reserves.
Purchases of minerals-in-place. In March 2012, we added 3,504 MBOE of proved reserves with the completion of the SWR Mergers.
Revisions. Net downward revisions of 6,615 MBOE consisted of downward revisions of 4,339 MBOE related to performance and downward revisions of 2,276 MBOE related to pricing. Downward price revisions of 2,276 MBOE were
attributable to the effects of lower product prices on the estimated quantities of proved reserves. Substantially all of the downward performance revisions were attributable to the Company's Andrews County Wolfberry drilling program.
Sales of minerals-in-place. In March 2012, SWR entered into a VPP with a third party and conveyed a term overriding royalty interest covering 725 MBOE of estimated future oil and gas production from certain properties to obtain funds to finance the SWR Mergers.
The following table summarizes changes in our estimated proved undeveloped reserves during 2012.
Proved
Undeveloped
Reserves
(MBOE)
As of December 31, 2011 25,085
Extensions and discoveries 14,468
Purchases of minerals-in-place 1,089
Revisions (4,644 )
Reclassified to proved developed (3,994 )
As of December 31, 2012 32,004
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We added 14,468 MBOE of proved undeveloped reserves from extensions and discoveries related to Permian Basin and Giddings Area drilling locations, including 1,207 MBOE of upgrades from probable to proved undeveloped. We had purchases of minerals-in-place of 1,089 MBOE in connection with the completion of the SWR Mergers. Downward revisions of 4,644 MBOE resulted primarily from performance revisions of 3,351 MBOE and pricing revisions of 1,293 MBOE. We also converted 3,994 MBOE of proved undeveloped reserves at December 31, 2012 to proved developed reserves during 2012 at a cost of approximately $126.4 million. We expect to develop approximately 6.5% of our proved undeveloped reserves in 2013 at a cost of approximately $41.3 million.
Supplemental Information
The following unaudited information is intended to supplement the consolidated
financial statements included in this Form 10-K with data that is not readily
available from those statements.
As of or for the Year Ended December 31,
2012 2011 2010
Oil and Gas Production Data:
Oil (MBbls) 3,821 3,727 3,375
Gas (MMcf) 8,072 8,594 10,750
Natural gas liquids (MBbls) 433 275 292
Total (MBOE) 5,599 5,434 5,459
Average Realized Prices (a) (b):
Oil ($/Bbl) $ 90.97 $ 92.43 $ 76.44
Gas ($/Mcf) $ 3.59 $ 5.30 $ 5.17
Natural gas liquids ($/Bbl) $ 38.95 $ 53.37 $ 42.47
Gain (Loss) on Settled Derivative Contracts(b):
($ in thousands, except per unit)
Oil: Net realized gain (loss) $ (3,410 ) $ 23,354 $ (7,685 )
Per unit produced ($/Bbl) $ (0.89 ) $ 6.27 $ (2.28 )
Gas: Net realized gain $ - $ 19,167 $ 17,560
Per unit produced ($/Mcf) $ - $ 2.23 $ 1.63
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As of or for the Year Ended December 31,
2012 2011 2010
Average Daily Production:
Oil (Bbls):
Permian Basin Area:
Delaware Basin 1,656 202 -
Other 5,369 6,060 5,601
Austin Chalk/Eagle Ford Shale 3,074 3,477 2,944
Other 341 472 702
Total 10,440 10,211 9,247
Gas (Mcf):
Permian Basin Area:
Delaware Basin 910 - -
Other 12,560 12,304 13,668
Austin Chalk/Eagle Ford Shale 2,034 2,142 2,179
Other 6,551 9,099 13,605
Total 22,055 23,545 29,452
Natural Gas Liquids (Bbls):
Permian Basin Area:
Delaware Basin 168 - -
Other 693 461 440
Austin Chalk/Eagle Ford Shale 267 212 237
Other 55 80 123
Total 1,183 753 800
Total Proved Reserves:
Oil (MBbls) 49,119 44,919 34,379
Natural gas liquids (MBbls) 9,182 4,617 3,436
Gas (MMcf) 102,336 88,876 79,497
Total (MBOE) 75,357 64,349 51,065
Standardized measure of discounted future net
cash flows $ 939,831 $ 938,513 $ 684,438
Total Proved Reserves by Area:
Oil (MBbls):
Permian Basin Area:
Delaware Basin 14,618 7,519 -
Other 25,955 28,226 24,769
Austin Chalk/Eagle Ford Shale 8,039 8,669 9,031
Other 507 505 579
Total 49,119 44,919 34,379
Natural Gas Liquids (MBbls):
Permian Basin Area:
Delaware Basin 4,249 - -
Other 4,345 4,016 2,859
Austin Chalk/Eagle Ford Shale 572 545 521
Other 16 56 56
Total 9,182 4,617 3,436
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As of or for the Year Ended December 31,
2012 2011 2010
Gas (MMcf):
Permian Basin Area:
Delaware Basin 20,651 6,887 -
Other 64,727 62,549 59,549
Austin Chalk/Eagle Ford Shale 6,130 6,271 5,620
Other 10,828 13,169 14,328
Total 102,336 88,876 79,497
Total Oil Equivalent (MBOE):
Permian Basin Area:
Delaware Basin 22,309 8,667 -
Other 41,087 42,667 37,553
Austin Chalk/Eagle Ford Shale 9,633 10,259 10,489
Other 2,328 2,756 3,023
Total 75,357 64,349 51,065
Exploration Costs (in thousands):
Abandonment and impairment costs:
South Louisiana $ 1,918 $ 2,105 $ 1,261
Permian Basin 453 673 18
Deep Bossier 1,323 16,771 2,522
Other 528 1,291 5,273
Total 4,222 20,840 9,074
Seismic and other 11,591 5,363 6,046
Total exploration costs $ 15,813 $ 26,203 $ 15,120
Oil and Gas Costs ($/BOE Produced):
Production costs $ 22.32 $ 18.60 $ 15.23
Production costs (excluding production taxes) $ 18.70 $ 14.79 $ 12.03
Oil and gas depletion $ 23.84 $ 18.72 $ 18.09
General and Administrative Expenses (in thousands):
Excluding non-cash employee compensation $ 30,889 $ 28,694 $ 21,690
Non-cash employee compensation (c) (404 ) 12,866 13,898
Total $ 30,485 $ 41,560 $ 35,588
Net Wells Drilled(d):
Developmental wells 92.3 111.8 112.5
Exploratory wells 4.3 3.6 2.5
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(a) Oil and gas sales for 2012 includes $8.3 million for the year ended December 31, 2012 of amortized deferred revenue attributable to the VPP granted effective March 1, 2012. The calculation of average realized sales prices for 2012 excludes production of 109,733 barrels of oil and 49,558 Mcf of gas for the year ended December 31, 2012 associated with the VPP.
(b) No derivatives were designated as cash flow hedges in the table above. All gains or losses on settled derivatives were included in other income (expense) - gain (loss) on derivatives.
(c) Non-cash employee compensation relates to the Company's non-equity award plans.
(d) Excludes wells being drilled or completed at the end of each period.
Operating Results
2012 Compared to 2011
The following discussion compares our results for the year ended December 31, 2012 to the year ended December 31, 2011. Unless otherwise indicated, references to 2012 and 2011 within this section refer to the respective annual periods.
Oil and gas operating results
Oil and gas sales, excluding amortized deferred revenues, decreased $10.4 million, or 3% in 2012, from 2011. Price variances accounted for $25.6 million of the decrease and production variances accounted for a $15.2 million increase. Oil and gas sales in 2012 also includes $8.3 million of amortized deferred revenue attributable to the VPP granted effective March 1, 2012 in connection with the SWR Mergers. Combined oil and gas production in 2012 (on a BOE basis) increased 3% compared to 2011. Our production mix continued to move favorably from 74% oil and NGL in 2011 to 76% in 2012. Oil production increased 3% in 2012 from 2011 while gas production decreased 6% in 2012 from 2011. Most of the decrease in gas production from 2011 levels was attributed to normal production declines from existing wells. In 2012, our realized oil price was 2% lower than 2011, and our realized gas price was 32% lower. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.
Production costs, consisting of lease operating expenses, production taxes and other miscellaneous marketing costs, increased 24% to $125 million in 2012 as compared to $101.1 million in 2011. The increase in production costs was due to a combination of an increase in the number of producing wells, higher costs of field services, including salt water disposal costs, and higher property taxes on Texas properties resulting from rising appraisal values.
Oil and gas depletion expense increased $31.8 million from 2011 to 2012 due to a $28.7 million increase related to rate variances and a $3.1 million increase due to production variances. Most of the increase in the depletion rate related to downward revisions in proved reserves in our Andrews County Wolfberry play. On a BOE basis, depletion expense increased 27% to $23.84 per BOE in 2012 from $18.72 per BOE in 2011. Depletion expense per BOE of oil and gas production is an operating metric that is indicative of our weighted average cost to find or acquire a unit of equivalent production. We may realize higher oil and gas depletion rates in future periods if our exploration and development activities result in higher finding costs.
We recorded a provision for impairment of property and equipment of $5.9 million during 2012 for certain non-core oil and gas properties in the Permian Basin and other non-core areas to reduce the carrying value of those properties to their estimated fair value. During 2011, we recorded a $10.4 million impairment of property and equipment for certain non-core oil and gas properties in the Permian Basin and other non-core areas to reduce the carrying value of those properties to their estimated fair value.
Exploration costs
We follow the successful efforts method of accounting; therefore, our results of operations are adversely affected during any accounting period in which significant seismic costs, exploratory dry hole costs, and unproved acreage impairments are expensed. In 2012, we charged to expense $15.8 million of exploration costs, as compared to $26.2 million in 2011.
Contract drilling services
We primarily utilize drilling rigs owned by our subsidiary, Desta Drilling, to drill wells in our exploration and development activities. Drilling services revenues received by Desta Drilling, along with the related drilling services costs pertaining to the net interest owned by CWEI, have been eliminated in our consolidated statements of operations and comprehensive income (loss). Drilling services costs related to external customers were $17.4 million in 2012 compared to $5.1 million in 2011.
General and Administrative
G&A expenses decreased $11.1 million from $41.6 million in 2011 to $30.5 million in 2012. Non-cash employee compensation expense related to non-equity incentive plans was a credit to expense of $404,000 in 2012 compared to $12.9 million expense in 2011. Lower commodity prices in 2012 resulted in a decrease in estimated future compensation expense from these plans, causing a partial reversal of previously accrued compensation expense. Excluding employee compensation related to non-equity incentive plans, G&A expenses increased from $28.7 million in 2011 to $30.9 million in 2012. The 2012 period included $2 million of non-recurring donations to charitable and 527 organizations.
Interest expense
Interest expense increased 17% from $32.9 million in 2011 to $38.7 million in 2012. Interest expense associated with our revolving credit facility increased by $6.3 million due primarily to an increase in borrowings, which increased from an average daily principal balance of $113.4 million in 2011 compared to $349.1 million in 2012.
Loss on early extinguishment of long-term debt
In 2011, we redeemed $225 million in aggregate principal amount of 7¾% Senior Notes due 2013 (the "2013 Senior Notes") in a tender offer and recorded a $5.5 million loss on early extinguishment of long-term debt consisting of a $2.8 million premium and a $2.7 million write-off of debt issuance costs.
Gain/loss on derivatives
We did not designate any derivative contracts in 2012 or 2011 as cash flow hedges; therefore, all cash settlements and changes resulting from mark-to-market valuations have been recorded as gain/loss on derivatives. In 2012, we reported a $14.4 million net gain on derivatives, consisting of a $17.8 million non-cash unrealized gain to mark our derivative positions to their fair value at December 31, 2012 and a $3.4 million realized loss on settled contracts. In 2011, we reported a $47 million net gain on derivatives, consisting of a $4.5 million non-cash unrealized gain to mark our derivative positions to their fair value at December 31, 2011 and a $42.5 million realized gain on settled contracts. Cash settlements in 2011 included $50 million from the early termination of contracts covering oil production for 2012 and 2013. Because oil and gas prices are volatile, and because we do not account for our derivatives as cash flow hedges, the effect of mark-to-market valuations on our gain/loss on derivatives can cause significant volatility in our results of operations.
Gain/loss on sales of assets and impairment of inventory
We recorded a net gain of $463,000 on sales of assets and impairment of inventory in 2012 compared to a net gain of $14.1 million in 2011. The 2011 gain related primarily to the sale of our two 2,000 horsepower drilling rigs and related equipment for a $13.2 million gain.
Income tax expense
Our estimated effective income tax rate in 2012 of 38.5% differed from the statutory federal rate of 35% due primarily to increases related to the effects of the Texas Margin Tax and certain non-deductible expenses, offset in part by tax benefits derived from excess statutory depletion deductions.
2011 Compared to 2010
The following discussion compares our results for the year ended December 31, 2011 to the year ended December 31, 2010. Unless otherwise indicated, references to 2011 and 2010 within this section refer to the respective annual periods.
Oil and gas operating results
Oil and gas sales in 2011 increased $78.9 million, or 24%, from 2010. Price variances accounted for an increase of $63.8 million while production variances accounted for the remaining $15.1 million increase. Although production in 2011 (on a BOE basis) remained constant compared to 2010 our production mix continued to move favorably from 67% oil and NGL in 2010 to 74% in 2011. Oil production increased 10% in 2011 from 2010 while gas production decreased 20% in 2011 from 2010. Most of the decrease in gas production from 2010 levels was attributed to a combination of normal production declines from existing wells and the loss of . . .
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