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| USEG > SEC Filings for USEG > Form 10-Q on 9-Aug-2012 | All Recent SEC Filings |
9-Aug-2012
Quarterly Report
The following is Management's Discussion and Analysis of significant factors that have affected liquidity, capital resources and results of operations during the three and six months ended June 30, 2012 and 2011. The following also updates information as to our financial condition provided in our 2011 Annual Report on Form 10-K. Statements in the following discussion may be forward-looking and involve risk and uncertainty (see "Forward Looking Statements") . The following discussion should also be read in conjunction with our condensed financial statements and the notes thereto.
General Overview
We are an independent energy company focused on the acquisition and development of oil and gas producing properties in the continental United States. Our business is currently focused in the Rocky Mountain region (specifically the Williston Basin of North Dakota and Montana), Texas and Louisiana, however, we do not intend to limit our focus to these geographic areas. We continue to focus on increasing production, reserves, revenues and cash flow from operations while managing our level of debt.
We currently explore for and produce oil and gas through a non-operator business model; however, we recently operated a Colorado oil and gas property for our own account and may expand our operations to other areas. As a non-operator, we rely on our operating partners to propose, permit and manage wells. Before a well is drilled, the operator is required to provide all oil and gas interest owners in the designated well the opportunity to participate in the drilling costs and revenues of the well on a pro-rata basis. After the well is completed, our operating partners also transport, market and account for all production.
We are also involved in the exploration for and development of minerals (molybdenum) through our ownership of the Mt. Emmons Molybdenum Project in Colorado. Gross capitalized dollar amounts invested in each of these areas at June 30, 2012 and December 31, 2011 were as follows:
(In thousands)
June 30, December 31,
2012 2011
Unproved oil and gas properties $ 12,749 $ 17,098
Proved oil and gas properties 109,081 102,405
Undeveloped mining properties 20,739 20,739
$ 142,569 $ 140,242
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Oil and Gas Activities
We have active agreements with several oil and gas exploration and production companies. Our working interest varies by project, but typically ranges from approximately 5% to 62%. These projects may result in numerous wells being drilled over the next three to five years. We are also actively pursuing the potential acquisition of additional exploration, development or production stage oil and gas properties or companies. The following table details our interests in producing wells as of June 30, 2012 and 2011.
June 30,
2012 2011
Gross Net(1) Gross Net(1)
Williston Basin:
Productive wells 32.00 9.82 19.00 7.15
Wells being drilled or awaiting completion 3.00 0.25 4.00 1.00
Gulf Coast/South Texas:
Productive wells 3.00 0.56 6.00 1.16
Wells being drilled or awaiting completion 1.00 0.20 2.00 0.27
Eagle Ford:
Productive wells 2.00 0.60 -- --
Wells being drilled or awaiting completion 1.00 0.30 -- --
Austin Chalk:
Productive wells 11.00 2.98 11.00 2.98
Wells being drilled or awaiting completion -- -- -- --
Other areas:
Productive wells -- -- -- --
Wells being drilled or awaiting completion -- -- 1.00 0.80
Total:
Productive wells 48.00 13.96 36.00 11.29
Wells being drilled or awaiting completion 5.00 0.75 7.00 2.07
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(1) Net working interests may vary over time under the terms of the applicable contracts.
Williston Basin, North Dakota
Rough Rider Prospect. We participate in fifteen 1,280 acre drilling units in the Rough Rider prospect with Brigham Oil & Gas, L.P. ("Brigham"), a subsidiary of Statoil. From August 24, 2009 to June 30, 2012, we have drilled and completed 20 gross Bakken Formation wells (7.34 net) and one gross Three Forks formation well (0.18 net) under the Drilling Participation Agreement with Brigham. Two additional gross wells (0.10 net) are expected to be drilled during the balance of 2012. Brigham operates all of the wells.
During the first six months of 2012, the Company completed three gross wells (0.45 net) in the Rough Rider prospect. Our net investment in the Rough Rider prospect wells was $3.9 million for the six months ended June 30, 2012.
Yellowstone and SEHR Prospects. We participate in twenty-seven gross 1,280 acre spacing units in the Yellowstone and SEHR prospects with Zavanna, LLC ("Zavanna"). Through June 30, 2012, we have drilled and completed 11 gross Bakken formation wells (2.31 net) in these prospects, including two gross wells (0.12 net) operated by Murex Petroleum and one gross well (0.01 net) operated by Slawson Exploration Company, Inc. Zavanna operates the remaining wells. At June 30, 2012, three additional gross wells (0.25 net) had been drilled and were awaiting completion.
During the first six months of 2012, we completed six gross wells (1.28 net) and drilled three gross wells (0.25 net) in the Yellowstone and SEHR prospects. Our net investment in the Yellowstone and SEHR prospect wells was $13.9 million during the six months ended June 30, 2012.
On January 24, 2012 (but effective December 1, 2011), we sold an undivided 75% of our undeveloped acreage in the Yellowstone and SEHR prospects to GeoResources, Inc. (56.25%) and Yuma Exploration and Production Company, Inc. (18.75%) for $16.7 million. Under the terms of the agreement, we retained the remaining 25% of our interest in the undeveloped acreage and our original working interest in the initial 10 developed wells in the prospects. Our average working interest in the remaining locations will be approximately 8.75% and net revenue interests in new wells after the sale are expected to be in the range of 6.7375% to 7.0%, proportionately reduced depending on Zavanna's actual working interest percentages.
On June 8, 2012, we sold an undivided 87.5% of our acreage in Daniels County, Montana to a third party for $3.7 million. Under the terms of the agreement, we retained a 12.5% working interest in the acreage and reserved overriding royalty interests ("ORRI") in leases we owned that had in excess of 81% NRI. The purchaser also committed to drill a vertical test well to depths sufficient to core the Bakken and Three Forks formations on or before December 31, 2015. The Company delivered an 80% NRI to the purchaser and a 1% ORRI to a land broker. The Company also paid the land broker a 10% commission for the cash consideration paid by the purchaser.
U.S. Gulf Coast (Onshore) / South Texas
We participate with several different operators in the U.S. Gulf Coast (onshore). At June 30, 2012, we had three gross producing wells (0.56 net) in this region. During the six months ended June 30, 2012, we drilled three gross wells (0.63 net) that were deemed to be nonproductive. Our net costs for these wells through June 30, 2012 were $585,000. One gross well (0.20 net) was in progress at June 30, 2012 and was determined to be non-productive.
In May 2012, we acquired a 26.5% initial working interest in approximately 6,766 gross acres in this area through a cash payment of $1.7 million. The promoted amount covers our portion of the costs for land, geological and geophysical work, as well as the dry hole costs for an initial test well in each of seven different prospects. Upon payout, our working interest will be reduced to 19.8%.
Our net investment in Gulf Coast / South Texas wells and properties was $2.0 million during the six months ended June 30, 2012.
Eagle Ford Shale
We participate in up to 114 gross (34 net) drilling locations in the Leona River and Booth-Tortuga Eagle Ford prospects with Crimson Exploration Inc. ("Crimson"). During the six months ended June 30, 2012, we drilled and completed one gross well (0.30 net) and drilled one gross well (0.30 net) that is expected to be completed during the third quarter of 2012. Our net investment in these wells during the first six months of 2012 was $2.9 million.
2012 Production Results
The following table provides a regional summary of our production during the
first six months of 2012:
Williston Basin Gulf Coast Eagle Ford Austin Chalk Total
/ South
Texas
First Six Months of 2012 Production
Oil (Bbl) 182,529 1,937 3,954 3,993 192,412
Gas (Mcf) 70,005 99,883 13,896 1,287 185,071
NGLs (BBs) 6,836 376 209 142 7,563
Equivalent (BOE) 201,032 18,960 6,479 4,349 230,820
Avg. Daily Equivalent (BOE/d) 1,105 104 36 24 1,268
Relative percentage 87% 8% 3% 2% 100%
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Additional Comparative Data
The following table provides information regarding selected production and
financial information for the quarter ended June 30, 2012 and the immediately
preceding three quarters.
For the Three Months Ended
June 30, March 31, December 31, September 30,
2012 2012 2011 2011
(in Thousands, except for production data)
Production (BOE) 118,783 112,036 118,663 120,198
Oil, gas and NGL production revenue $ 8,522 $ 8,335 $ 8,846 $ 8,408
Unrealized and realized derivative
(loss) gain $ 1,764 $ (202 ) $ (1,738 ) $ 1,564
Lease operating expense $ 1,630 $ 2,010 $ 1,954 $ 1,811
Production taxes $ 928 $ 883 $ 921 $ 832
DD&A $ 4,030 $ 3,641 $ 4,230 $ 3,862
General and administrative $ 1,760 $ 1,897 $ 1,883 $ 1,829
Mineral holding costs $ 206 $ 110 $ 140 $ 266
Water treatment plant $ 436 $ 509 $ 454 $ 497
Income (loss) from continuing
operations $ 624 $ (832 ) $ 309 $ 130
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Results of Operations
Three Months Ended June 30, 2012 compared to Three Months Ended June 30, 2011
During the three months ended June 30, 2012, we recorded a net loss after taxes of $990,000 as compared to a net loss after taxes of $75,000 during the same period of 2011. Significant components of the change in operating revenues and results of operations for the three months ended June 30, 2012 as compared to the three months ended June 30, 2011 are as follows:
Oil and Gas Operations. Oil and gas operations produced operating income of $1.4 million during the quarter ended June 30, 2012 and 2011. The following table summarizes production volumes, average sales prices and operating revenues for the three months ended June 30, 2012 and 2011:
Three Months Ended
June 30, Increase
2012 2011 (Decrease)
Production volumes
Oil (Bbls) 99,830 56,109 43,721
Natural gas (Mcf) 95,299 238,825 (143,526 )
Natural gas liquids (Bbls) 3,070 6,500 (3,430 )
Equivalent (BOE) 118,783 102,413 16,370
Avg. Daily Equivalent (BOE/d) 1,305 1,125 180
Average sales prices
Oil (per Bbl) $ 81.22 $ 99.77 $ (18.55 )
Natural gas (per Mcf) 2.92 4.46 (1.54 )
Natural gas liquids (per Bbl) 44.29 55.85 11.56
Operating revenues (in thousands)
Oil $ 8,108 $ 5,598 $ 2,510
Natural gas 278 1,064 (786 )
Natural gas liquids 136 363 (227 )
Total operating revenue 8,522 7,025 1,497
Lease operating expense (1,630 ) (1,289 ) (341 )
Production taxes (928 ) (667 ) (261 )
Impairment (523 ) - (523 )
Income before depreciation, depletion
and amortization 5,441 5,069 372
Depreciation, depletion and amortization (4,030 ) (3,120 ) (910 )
Income $ 1,411 $ 1,949 $ (538 )
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During the three months ended June 30, 2012, we produced approximately 118,783 barrels of oil equivalent (BOE), or an average of 1,305 BOE/day. Portions of our natural gas production are sent to gas processing plants to extract from the gas various natural gas liquids ("NGLs") that are sold separately from the remaining natural gas. We sell some of our gas before processing and some after processing but in both cases receive revenues based on a share of post-processing proceeds from plant sales of the extracted NGLs and the remaining natural gas. In the table above, our share of processing costs are classified in lease operating expenses.
We recognized $8.5 million in revenues during the three months ended June 30, 2012 as compared to $7.0 million during the same period of the prior year. This $1.5 million increase in revenue is primarily due to higher oil sales volumes in 2012 when compared to 2011. Revenue from gas sales was lower in the three months ended June 30, 2012 when compared to the same period in 2011, primarily due to production declines from wells in the Gulf Coast.
Our average net realized price for the three months ended June 30, 2012 was $71.74 per BOE compared with $68.59 for the same period in 2011. The increase in our equivalent realized price for production corresponds with a higher percentage of our production coming from oil in 2012 when compared with 2011. Due to takeaway constraints, the discount, or differential, for oil prices in the Williston Basin has ranged from $10 to $25 per barrel during the first six months of 2012. Until additional takeaway capacity is available, we expect this differential to continue and that our oil sales revenue will be affected by the lower prices.
Lease operating expense of $1.6 million for the three months ended June 30, 2012 was comprised of $1.3 million in lease operating expense and $321,000 in workover expense. The $341,000 increase in total lease operating expense in 2012 as compared to 2011 is primarily a result of an increase in the number of producing wells.
At June 30, 2012, the Company recorded a proved property impairment of $523,000 related to its oil and gas assets, primarily due to a decline in natural gas prices. There were no proved property impairments recorded during the three months ended June 30, 2011.
Our depletion, depreciation and amortization (DD&A) rate for the three months ended June 30, 2012 was $33.92 per BOE compared to $30.46 per BOE for the same period in 2011. We have been impacted by higher DD&A rates related to our Williston Basin wells due to increases in drilling and completion costs for wells in this region. Our DD&A rate can also fluctuate as a result of impairments, divestitures, changes in the mix of our production, the underlying proved reserve volumes and estimated costs to drill and complete proved undeveloped reserves.
During the balance of 2012 we anticipate completing wells that were drilled during the first two quarters of 2012 as well as drilling and completing new wells. We also anticipate that our production rates will increase as a result of these activities. In particular, we expect that oil volumes will increase as we drill and complete oil wells in the Williston Basin and other areas. The anticipated net increase in production is projected to add additional cash flows from operations. However, natural gas and natural gas liquids volumes are expected to continue to decrease as production declines from the Gulf Coast producing wells. However, various factors, including extensive workover costs on existing wells, lower commodity prices, commodity price differentials, cost overruns on projected drilling projects, unsuccessful wells or other development activities and/or faster than expected declines in production from existing wells, would have a negative effect on production, cash flows and earnings from the oil and gas segment and could cause actual results to differ materially from those we expect.
Mt. Emmons and Water Treatment Plant Operations. We recorded $436,000 in costs and expenses for the water treatment plant and $206,000 for holding costs for the Mt. Emmons molybdenum property during the three months ended June 30, 2012. During the three months ended June 30, 2011, we recorded $498,000 in operating costs related to the water treatment plant and $37,000 in holding costs. Holding costs during 2011 were partially funded by another party under an operating agreement. As a result of the termination of this agreement in 2011, our 2012 costs are higher as we now bear all the costs associated with the project.
General and Administrative. General and administrative expenses decreased by $378,000 during the three months ended June 30, 2012 as compared to general and administrative expenses for the three months ended June 30, 2011. Lower general and administrative costs in 2012 are primarily a result of $254,000 lower stock option expense, $142,000 lower bonus accrual and $110,000 lower compensation expense. These decreases in costs were partially offset by an increase in contract services of $137,000.
Other income and expenses. We recognized an unrealized and realized derivative gain of $1.8 million in the second quarter of 2012 compared to a gain of $1.1 million for the same period in 2011. The 2012 amount includes a gain on unrealized changes in the fair value of our commodity derivative contracts of $1.8 million and realized cash settlement losses on derivatives of $6,000.
Gain on the sale of marketable securities from the sale of shares of Sutter Gold Mining decreased to $7,000 during the quarter ended June 30, 2012 from $9,000 during the quarter ended June 30, 2011.
There was no gain on the sale of assets during the quarter ended June 30, 2012 as compared to a gain of $137,000 during the quarter ended June 30, 2011 from the sale of surplus equipment.
We recorded equity losses of $91,000 and $65,000 from the investment in SST during the quarters ended June 30, 2012 and 2011, respectively. Equity losses from the investment in SST are expected to continue until such time as SST properties are sold, equity losses reduce our investment to zero or we sell the investment.
Interest income decreased to $1,000 during the quarter ended June 30, 2012 from $10,000 during the quarter ended June 30, 2011. The decrease is a result of lower amounts of cash invested in interest bearing instruments during the quarter, and lower interest rates received on those investments.
Interest expense increased to $36,000 during the quarter ended June 30, 2012 from $34,000 during the quarter ended June 30, 2011.
Discontinued operations. We recorded income of $26,000, net of taxes from Remington Village during the quarter ended June 30, 2012 and income of $123,000, net of taxes for the quarter ended June 30, 2011. The decrease in income when comparing the quarter ended June 30, 2012 to the quarter ended June 30, 2011 is primarily a result of an increase in the benefit of deferred taxes. The increase was partially offset by higher interest expense and higher contract services costs for the drainage system. On July 9, 2012, the Company entered into a Letter of Intent ("LOI") to sell Remington Village for $16.0 million. As a result of the anticipated sales amount, at June 30, 2012, the Company recorded a non-cash impairment of $1.3 million net of taxes to adjust the carrying value of the project to the expected sales value. Ultimately, we could not reach mutually agreeable terms for the sale and the LOI was terminated. We will continue to market the property for sale.
We therefore recorded a net loss after taxes of $990,000, or $0.04 per share basic and diluted, during the quarter ended June 30, 2012 as compared to a net loss after taxes of $75,000, or less than $0.01 per share basic and diluted, during the quarter ended June 30, 2011.
Six Months Ended June 30, 2012 compared to Six Months Ended June 30, 2011
During the six months ended June 30, 2012, we recorded a net loss after taxes of $1.4 million as compared to a net loss after taxes of $2.3 million during the same period of 2011. Significant components of the change in operating revenues and results of operations for the six months ended June 30, 2012 as compared to the six months ended June 30, 2011 are as follows:
Oil and Gas Operations. Oil and gas operations produced operating income of $3.2 million during the six months ended June 30, 2012 as compared to operating income of $1.8 million during the six months ended June 30, 2011. The increase in earnings from oil and gas operations is primarily due to (a) a $4.7 million increase in oil revenues during 2012 compared to 2011 and (b) $1.0 million lower lease operating expenses in the six months ending June 30, 2012 as compared to the same period of the prior year. This increase was partially offset by $1.8 million higher depletion expense in 2012 and a $1.6 million decrease in natural gas and natural gas liquids revenues. The following table summarizes production volumes, average sales prices and operating revenues for the six months ended June 30, 2012 and 2011:
Six Months Ended
June 30, Increase
2012 2011 (Decrease)
Production volumes
Oil (Bbls) 192,412 123,459 68,953
Natural gas (Mcf) 185,071 412,580 (227,509 )
Natural gas liquids (Bbls) 7,563 11,281 (3,718 )
Equivalent (BOE) 230,820 203,503 27,317
Avg. Daily Equivalent (BOE/d) 1,268 1,124 144
Average sales prices
Oil (per Bbl) $ 82.77 $ 90.77 $ (8.00 )
Natural gas (per Mcf) 2.98 4.61 (1.63 )
Natural gas liquids (per Bbl) 50.38 52.92 (2.54 )
Operating revenues (in thousands)
Oil $ 15,925 $ 11,206 $ 4,719
Natural gas 551 1,901 (1,350 )
Natural gas liquids 381 597 (216 )
Total operating revenue 16,857 13,704 3,153
Lease operating expense (3,640 ) (4,685 ) 1,045
Production taxes (1,811 ) (1,349 ) (462 )
Impairment (523 ) - (523 )
Income before depreciation, depletion
and amortization 10,883 7,670 3,213
Depreciation, depletion and amortization (7,671 ) (5,905 ) (1,766 )
Income $ 3,212 $ 1,765 $ 1,447
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During the six months ended June 30, 2012, we produced approximately 230,820 barrels of oil equivalent (BOE), or an average of 1,268 BOE/day. Portions of our natural gas production are sent to gas processing plants to extract from the gas various natural gas liquids ("NGLs") that are sold separately from the remaining natural gas. We sell some of our gas before processing and some after processing but in both cases receive revenues based on a share of post-processing proceeds from plant sales of the extracted NGLs and the remaining natural gas. In the table above, our share of processing costs are classified in lease operating expenses.
We recognized $16.9 million in revenues during the six months ended June 30, 2012 as compared to $13.7 million during the same period of the prior year. This $3.2 million increase in revenue is primarily due to higher oil sales volumes in 2012 when compared to 2011. Revenue from gas sales is lower in the six months ended June 30, 2012 when compared to the same period in 2011, primarily due to production declines from wells in the Gulf Coast.
Our average net realized price for the six months ended June 30, 2012 was $73.03 per BOE compared with $67.34 for the same period in 2011. The increase in our equivalent realized price for production corresponds with a higher percentage of our production coming from oil in 2012 when compared with 2011. Due to takeaway . . .
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