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U.S. Energy Corp. Reports Second Quarter 2014 Highlights and Selected Financial Results

RIVERTON, Wyo., Aug. 11, 2014 (GLOBE NEWSWIRE) -- U.S. Energy Corp. (Nasdaq:USEG) (the "Company"), today reported its second quarter 2014 highlights and selected financial results for the quarter ended June 30, 2014 and provided an operations update.

Selected Highlights, Capital Budget, Acquisitions and Divestitures for the Three and Six Months Ended June 30, 2014

Three Months Ended June 30, 2014

  • Produced 116,499 barrels of oil equivalent ("BOE"), or 1,280 BOE per day ("BOE/D"), from 117 gross (18.14 net) wells. The Company averaged 1,352 net BOE/D for the month of June 2014.
  • The Company recorded net income after taxes during the quarter of $56,000, or $0.00 per share basic and diluted, as compared to net income after taxes of $573,000, or $0.02 per share basic and diluted, during the same period of 2013.
  • Excluding non-recurring items and mark-to-market gains and losses on derivative instruments, Adjusted Net Income (non-GAAP) was $293,000 during the three months ended June 30, 2014, or $0.01 per basic and diluted share. Excluding similar non-cash items, Adjusted Net Income (non-GAAP) was $244,000 for the second quarter of 2013, or $0.01 per basic and diluted share. Adjusted Net Income is a non-GAAP financial measure. Please refer to the reconciliation in this release for additional information about this measure.
  • Oil and gas operations generated operating income of $3.0 million during the quarter ended June 30, 2014 as compared to operating income of $2.1 million during the quarter ended June 30, 2013.
  • The Company recognized $9.1 million in revenues during the three months ended June 30, 2014 as compared to $7.9 million during the same period of the prior year. The $1.2 million increase in revenue is primarily due to higher oil and gas prices and higher gas sales volumes in the second quarter of 2014 when compared to the same period in 2013.
  • At June 30, 2014, we had $4.3 million in cash and cash equivalents. Our working capital (current assets minus current liabilities) was $5.4 million.
  • Earnings before interest, income taxes, depreciation, depletion and amortization, accretion of discount on asset retirement obligations, non-cash impairments, unrealized derivative gains and losses and non-cash compensation expense ("Modified EBITDAX"), was $4.2 million for the three months ended June 30, 2014, an increase of 12.5% compared to a Modified EBITDAX of $3.8 million for the three months ended June 30, 2013. Please refer to the reconciliation in this release for additional information about this measure.

Six Months Ended June 30, 2014

  • Produced 221,592 BOE, or an average of 1,224 BOE/D.
  • The Company recorded net income after taxes of $306,000, or $0.01 per share basic and diluted, as compared to a net loss after taxes of $5.3 million, or $0.19 per share basic and diluted, during the same period of 2013.
  • Excluding non-recurring items and mark-to-market gains and losses on derivative instruments, Adjusted Net Income (non-GAAP) was $717,000 during the six months ended June 30, 2014, or $0.03 per basic and diluted share. Excluding similar non-cash items, Adjusted Net Income (non-GAAP) was $791,000 for the six months ending June 30, 2013, or $0.03 per basic and diluted share. Adjusted Net Income is a non-GAAP financial measure. Please refer to the reconciliation in this release for additional information about this measure.
  • Oil and gas operations generated operating income of $5.9 million during the six months ended June 30, 2014 as compared to operating income of $3.8 million during the six months ended June 30, 2013, excluding the $5.8 million non-cash impairment charge taken on our oil and gas properties during the six months ended June 30, 2013.
  • The Company recognized $17.4 million in revenues during the six months ended June 30, 2014 as compared to $15.8 million during the same period in 2013. The $1.6 million increase in revenue is primarily due to higher oil and gas sales volumes and higher oil and gas prices in the first six months of 2014 as compared to the first six months of 2013.
  • We received an average of $2.9 million per month from our producing wells with an average operating cost of $510,000 per month (including workover costs) and production taxes of $250,000, for average net cash flows of $2.1 million per month from oil and gas production before non-cash depletion expense.
  • Earnings before interest, income taxes, depreciation, depletion and amortization, accretion of discount on asset retirement obligations, non-cash impairments, unrealized derivative gains and losses and non-cash compensation expense ("Modified EBITDAX"), was $8.3 million for the six months ended June 30, 2014, an increase of 2.4% compared to a Modified EBITDAX of $8.1 million for the six months ended June 30, 2013. Please refer to the reconciliation in this release for additional information about this measure.

2014 Capital Budget

Under our $30.2 million capital expenditures budget for 2014, we have spent approximately $17.3 million to fund our 2014 oil and gas drilling programs through June 30, 2014. The remaining $12.9 million is currently budgeted to be spent on exploration, development and acquisition initiatives in South Texas and in the Williston Basin of North Dakota.*

Acquisitions and Divestitures

Q2 Dimmit County Acquisition

On May 7, 2014, the Company entered into a Participation Agreement with a private South Texas based oil and gas company ("Seller") to acquire 33% of the Seller's interest in approximately 12,100 gross (3,384 net) acres in Dimmit County, Texas. The acreage consists of 4,020 gross (1,181 net) acres of primary leasehold acreage and 8,080 gross (2,203 net) acres of farm-in acreage, to be earned through a continuous drilling program. The farm-in acreage has an initial two well commitment and a 12.5% working interest carry for the leaseholder (the "Farmor") in the first 10 wells. After 100% payout of all costs for the first 10 wells that are drilled under the farm-in program, the Farmor will back in for their 12.5% retained working interest in the prospect. The Seller also retained a 25% working interest back-in after 115% of project payout has been received by the Company. The Company paid $3.9 million to enter into the transaction, which included leasehold and farm-in acquisition costs as well as our proportionate share of drilling costs for the initial test well in the prospect.

Divestiture

On May 27, 2014, the Company entered into a Purchase and Sale Agreement to sell certain Williston Basin assets. Under the terms of the sale agreement, the Company sold its interest in approximately 285 net acres and 16 gross (0.62 net) producing wells in Williams and McKenzie Counties, North Dakota. The transaction closed in June 2014 with an effective date of January 1, 2014. The Company received $12.2 million at closing which included $681,000 in adjustments related to revenue receivable and accounts payable through the date of closing. The $11.5 million balance of the sale proceeds was recorded as a credit to our full cost pool.

Operations Update

South Texas - Buda Limestone formation

The Company currently participates in drilling programs with three operators in Zavala and Dimmit Counties, Texas which are prospective for the Buda Limestone and other formations. We currently participate in approximately 35,221 gross (9,130 net) acres in the region. At June 30, 2014, we had 27 gross (7.48 net) producing wells in these prospects comprised of 13 gross (3.60 net) Buda Limestone wells, 3 gross (0.90 net) Eagle Ford Shale wells and 11 gross (2.98 net) Austin Chalk wells. During the quarter ended June 30, 2014, the Company produced approximately 538 net BOE/D from this region, which represents an approximate 32% increase compared to Q1 2014's average net daily production from the region.

Booth Tortuga (30% working interest / ~22.5% net revenue interest)

  • The Beeler #5H ST well was spud on March 25, 2014. The well was completed naturally without fracture stimulation and commenced production in late April 2014. The well had a peak early 24-hour flow back rate of 241 BOE/D and a 30 day average production rate of 122 BOE/D (~52% oil).
  • The Beeler Unit A #9H well was spud on March 26, 2014. The well was completed naturally without fracture stimulation and commenced production in late April 2014. The well had a peak early 24-hour flow back rate of 883 BOE/D and a 30 day average production rate of 326 BOE/D (~53% oil).
  • The Beeler Unit D #16H well was spud on April 18, 2014. The well was drilled to a vertical depth of approximately 7,000 feet with dual laterals of approximate 4,000 feet each. The well was completed naturally without fracture stimulation and commenced production the second week of June 2014. The well had a peak early 24-hour flow back rate of 1,083 BOE/D (~89% oil) and a 30 day average production rate of 723 BOE/D (~78% oil).
  • The Beeler #17H well was spud on May 13, 2014. The well was completed naturally without fracture stimulation and commenced production the second week of June 2014. The well had a peak early 24-hour flow back rate of 1,326 BOE/D (~88% oil) and a 30 day average production rate of 1,109 BOE/D (~87% oil).
  • The Beeler Unit F #19H well was spud on June 10, 2014. The well was completed naturally without fracture stimulation and commenced production the second week of July 2014. The well had a peak early 24-hour flow back rate of 1,458 BOE/D (~78% oil) and during the first 28 days of production the well had an average production rate of 1,204 BOE/D (~80% oil).
  • The Beeler 8H well was fracture stimulated with 12 stages during the third week in June 2014. A production increase was not realized as a result of the stimulation and it is theorized that the nearby fractured zones were depleted by an offsetting well. The well is still producing however, and the operator continues to monitor the well's performance.
  • The Beeler Unit C #20H well was spud July 3, 2014. The well was drilled to a total depth of 16,574 feet, which included an approximate 9,474 foot lateral, the longest lateral to date in the program thus far. The operator continues to monitor the early production data from the well, which is comparable to the early flow back results of the Beeler #17H well.

The Beeler # 17H, Beeler Unit F #19H and the Beeler Unit C #20H well costs have been approximately $2.6 million per well. Going forward we are currently scheduled to drill an additional four gross Buda wells with Contango during the balance of the year. The drilling rig utilized in our program with Contango is currently drilling a well at another site in which we do not participate. We anticipate that the rig will return to drill our next participated well in the Booth –Tortuga acreage block in early September 2014. All four wells are proposed to be drilled with lateral lengths of 9,000 plus feet.

AMI Election

Under an Area of Mutual Interest Election, the Company acquired a 7.5% working interest in an additional 800 gross (~60 net) acres in the Booth-Tortuga prospect. This acreage is operated by a private Texas-based company which has proposed to drill two wells in this acreage. The acreage block lies between the Beeler Unit D #16H and the Beeler Unit A #9H well locations.

  • The Bruce Weaver #2H well was spud June 6, 2014. The well was drilled to a total depth of 13,290 feet, which included an approximate 6,765 foot lateral. The well was completed naturally without fracture stimulation and had an initial production rate of 894 BOE on a 22/64th choke. During the first 10 days of production the well averaged approximately 760 gross BOE/D. During the early flow back, the operator has flared the associated gas from the well, which is not included in the 10-day initial production rate. The well is currently being tied in to a sales line to capture the gas sales, which have been approximately 1,000 MCF/D, or approximately 167 gross additional barrels of oil equivalent based on the first 10 days of production.
  • The Bruce Weaver #1 RE (re-entry) well also targeting the Buda formation is scheduled to spud mid-August 2014.

Q2 Dimmit County Acquisition (~33.3% working interest / ~22.5% net revenue interest)

  • In our recently acquired acreage block in Dimmit County, Texas, the initial test well was spud on May 5, 2014 and was drilled to a measured depth of approximately 11,297 feet including an approximate 5,000 foot lateral. The well was fracture stimulated during the first week of August 2014 with 17 stages. The operator is currently monitoring the flow back of the well.
  • The second well in the program was spud on June 23, 2014. The well was drilled to a measured depth of approximately 11,000 feet, including an approximate 4,600 foot lateral. The well is scheduled to be fracture stimulated during the third week of August 2014.
  • The third well in the program is scheduled to spud mid-September 2014.

Williston Basin, North Dakota

The Company participates in drilling programs with numerous operators in the Williston Basin of North Dakota. We participate in approximately 74,280 gross (2,939 net) acres in Williams, McKenzie and Mountrail Counties, North Dakota. At June 30, 2014, the Company participated in 87 gross (10.10 net) Bakken and Three Forks formation wells. During the quarter ended June 30, 2014, the Company produced approximately 660 net BOE/D from this region, which represents a slight decrease over Q1 2014's average daily production of 679 net BOE/D, primarily due to the divestiture of assets in North Dakota mentioned earlier in this release.

The following table summarizes current activity under our Williston Basin drilling programs.

Well Name Operator Formation
Spud Date
Working
Interest
Net Revenue
Interest

Status
Hovde 33-4 #3H Statoil Bakken 10/28/2013 2.45% 1.94% Producing
Hovde 33-4 #4H Statoil Bakken 11/8/2013 2.45% 1.94% Producing
Lloyd 34-3 #3H Statoil Bakken 12/25/2013 2.15% 1.70% Producing
Caper 2-15-22H Emerald Oil Inc. Bakken 12/7/2013 0.73% 0.57% Producing
Pirate 2-2-11H Emerald Oil Inc. Bakken 2/24/2014 3.67% 2.82% Producing
Pirate 3-2-11H Emerald Oil Inc. Three Forks 1/3/2014 3.67% 2.82% Producing
Rita 24X-34A XTO Bakken 1/19/2014 0.20% 0.16% Producing
Rita 24X-34E XTO Bakken 1/19/2014 0.20% 0.16% Producing
Talon 3-9-4H Emerald Oil Inc. Bakken 3/7/2014 0.34% 0.27% Completion pending
Slugger 5-16-21H Emerald Oil Inc. Bakken 3/9/2014 0.37% 0.28% Completion pending
Talon 5-9-4H Emerald Oil Inc. Bakken 4/23/2014 0.34% 0.27% Completion pending
Slugger 3-16-21H Emerald Oil Inc. Bakken 6/5/2014 0.37% 0.28% Completion pending
Talon 6-9-4H Emerald Oil Inc. Three Forks 7/21/2014 0.34% 0.28% Drilling
Slugger 6-16-21H Emerald Oil Inc. Bakken 8/17/2014 0.37% 0.28% Scheduled to drill
Talon 7-9-4H Emerald Oil Inc. Bakken 9/13/2014 0.34% 0.28% Scheduled to drill
Slugger 7-16-21H Emerald Oil Inc. Bakken 10/10/2014 0.37% 0.28% Scheduled to drill
Average: 1.15% 0.90%

CEO Statement

"At the mid-year point I am pleased to report a second successive profitable quarter of 2014 on behalf of the Company and its shareholders. We have made strategic acquisitions and divestitures during the first half of the year which have enabled the Company to maintain a low debt level while adding additional prospects and development opportunities in South Texas," said Keith Larsen, the Company's CEO. "We continue to delineate the potential of our prospects in South Texas, notably through drilling a dual lateral well, participating in the fracture stimulation of an existing wellbore and through extending the lateral length on the Beeler #20 well to over 9,000 feet. Additionally, we are fracture stimulating both of the initial test wells in our Q2 2014 South Texas acquisition acreage and will evaluate those results in the coming weeks. Looking forward, based on our recent completions in South Texas, we are confident that our third quarter results will reflect further production gains," he added.

Financial Highlights

The following table sets forth selected financial information for the three and six months ended June 30, 2014 and 2013. This information is derived from the unaudited financial statements included in our Quarterly Report on Form 10-Q for the three months ended June 30, 2014, and should be read in conjunction with the Form 10-Q and the financial statements contained therein, including the notes to the financial statements.

U.S. ENERGY CORP.
SELECTED FINANCIAL DATA
(Unaudited)
(Amounts in thousands, except share and per share amounts)
June 30, December 31,
2014 2013
Balance Sheets:
Cash and cash equivalents $ 4,254 $ 5,855
Current assets $ 10,970 $ 13,161
Current liabilities $ 5,533 $ 7,191
Working capital $ 5,437 $ 5,970
Total assets $ 124,634 $ 126,801
Long-term obligations $ 9,675 $ 10,553
Shareholders' equity $ 109,426 $ 109,057
Shares Outstanding 27,896,697 27,735,878
For the three months ended June 30, For the six months ended June 30,
2014 2013 2014 2013
Statements of Operations:
Operating revenues $ 9,128 $ 7,915 $ 17,384 $ 15,794
Income (loss) from operations $ 769 $ 151 $ 1,396 $ (5,974)
Other income & expenses $ (713) $ 216 $ (1,090) $ 211
Discontinued operations, net of taxes $ -- $ 206 $ -- $ 438
Net income (loss) $ 56 $ 573 $ 306 $ (5,325)
Net income (loss) per share
Basic and diluted $ -- $ 0.02 $ 0.01 $ (0.19)
Weighted average shares outstanding
Basic 27,785,280 27,682,272 27,761,837 27,674,729
Diluted 28,237,883 27,682,272 28,195,116 27,674,729

Non-GAAP Financial Measures

Modified EBITDAX

In addition to reporting net income (loss) as defined under GAAP, in this release we also present net earnings before interest, income taxes, depreciation, depletion, and amortization, accretion of discount on asset retirement obligations, non-cash impairments, unrealized derivative gains and losses and non-cash compensation expense ("Modified EBITDAX"), which is a non-GAAP performance measure. Modified EBITDAX excludes certain items that the Company believes affect the comparability of operating results and can exclude items that are generally one-time or whose timing and/or amount cannot be reasonably estimated. Modified EBITDAX is a non-GAAP measure that is presented because the Company believes that it provides useful additional information to investors, as a performance measure. We believe that Modified EBITDAX is useful to investors because similar measures are frequently used by securities analysts, investors, and other interested parties in their evaluation of companies in the energy industry. Our management uses Modified EBITDAX to manage our business, including preparation of our annual operating budget and financial projections. Modified EBITDAX does not represent, and should not be considered an alternative to, GAAP measurements such as net income (loss) (its most directly comparable GAAP measure), or as a measure of liquidity, and our calculations thereof may not be comparable to similarly titled measures reported by other companies. Our management does not view Modified EBITDAX in isolation and also uses other measurements, such as net income (loss) and revenues, to measure operating performance. The following table provides a reconciliation of net income (loss) to Modified EBITDAX for the periods presented:

For the three months ended June 30, For the six months ended June 30,
2014 2013 2014 2013
Net income (loss) $ 56 $ 573 $ 306 $ (5,325)
Impairment of oil and natural gas properties -- -- -- 5,828
Accretion of asset retirement obligation 10 9 19 19
Non-cash compensation expense 136 122 296 249
Unrealized (gain) loss on commodity derivatives 238 (328) 411 288
Interest expense 149 111 245 226
Depreciation, depletion and amortization 3,651 3,282 7,013 6,814
Modified EBITDAX (Non-GAAP) $ 4,240 $ 3,769 $ 8,290 $ 8,099

Adjusted Net Income (Loss)

Adjusted Net Income (Loss) is another supplemental non-GAAP financial measure that is used by management and external users of the Company's condensed consolidated financial statements. The Company defines Adjusted Net Income as net income after adjusting for the impact of certain non-recurring items, including the change in the fair value of derivative instruments, impairments of oil and gas properties, and certain non-recurring charges to the reported net income (loss) as defined under GAAP set forth in the table below.

The following table provides a reconciliation of net income (loss) (GAAP) to Adjusted Net Income (Loss) (non-GAAP):

For the three months ended June 30, For the six months ended June 30,
2014 2013 2014 2013
Net income (loss) $ 56 $ 573 $ 306 $ (5,325)
Impairment of oil and natural gas properties -- -- -- 5,828
Change in fair value of derivative instruments 238 (328) 411 288
Adjusted net income $ 294 $ 245 $ 717 $ 791
Adjusted earning per share:
Basic $ 0.01 $ 0.01 $ 0.03 $ 0.03
Diluted $ 0.01 $ 0.01 $ 0.03 $ 0.03
Weighted average shares outstanding
Basic 27,785,280 27,682,272 27,761,837 27,674,729
Diluted 28,237,883 27,682,272 28,195,116 27,674,729

About U.S. Energy Corp.

U.S. Energy Corp. is a natural resource exploration and development company with oil and gas assets located primarily in North Dakota and Texas. The Company is headquartered in Riverton, Wyoming and trades on the NASDAQ Capital Market under the symbol "USEG".

The U.S. Energy Corp. logo is available at http://www.globenewswire.com/newsroom/prs/?pkgid=5043

* Actual capital expenditures for each regional drilling program are contingent upon timing, well costs and success. If our drilling initiatives in any program are not initially successful, or do not progress as projected, funds allocated for those drilling programs may be allocated to other drilling and/or acquisitions in due course. The projected number of gross and net wells could vary in each of these cases.

To view the Company's Financial Statements and Management's Discussion and Analysis, please see the Company's 10-Q for the three and six months ended June 30, 2014, which is available at www.sec.gov and www.usnrg.com.

Disclosure Regarding Forward-Looking Statement

This news release includes statements which may constitute "forward-looking" statements, usually containing the words "will," "anticipates," "believe," "estimate," "project," "expect," "target," "goal," or similar expressions. Forward looking statements in this release relate to, among other things, U.S. Energy's expected future production and capital expenditures and projects (including projects to be pursued with its industry partners), its drilling and fracing of wells with industry partners and potential additional drilling opportunities, its ownership interests in those wells and the oil and natural gas targets or goals for the wells.. There is no assurance that any of the wells referenced in this press release will be economic. Initial and current production results from a well are not necessarily indicative of its longer-term performance. The forward-looking statements are made pursuant to the safe harbor provision of the Private Securities Litigation Reform Act of 1995. Forward-looking statements inherently involve risks and uncertainties that could cause actual results to differ materially from the forward-looking statements. Factors that would cause or contribute to such differences include, but are not limited to, dry holes and other unsuccessful development activities, higher than expected expenses or decline rates from production wells, future trends in commodity and/or mineral prices, the availability of capital, competitive factors, and other risks described in the Company's filings with the SEC (including, without limitation, the Form 10-K for the year ended December 31, 2013 and the Form 10-Q for the quarter ended June 30, 2014) all of which are incorporated herein by reference. By making these forward-looking statements, the Company undertakes no obligation to update these statements for revision or changes after the date of this release.

CONTACT: Reggie Larsen Director of Investor Relations U.S. Energy Corp. 1-800-776-9271 Reggie@usnrg.com

Source:U.S. Energy Corp.