Black Ridge Oil & Gas Announces Second Quarter 2015 Results

MINNETONKA, Minn., Aug. 13, 2015 /PRNewswire/ -- Black Ridge Oil & Gas, Inc. ("the Company") ANFC, a growth-oriented exploration and production company focused on non-operated Bakken and Three Forks properties, today announced financial and operating results for the three and six months ended June 30, 2015.

Second Quarter 2015 Company Highlights

• Quarterly production increased 57% over the second quarter of 2014 to 102.2 thousand barrels of oil equivalent ("MBoe"), an average of approximately 1,123 barrels of oil equivalent per day ("Boe/d")
• Oil and gas sales totaled $5.1 million, an increase of 75% over the first quarter of 2015 and a decrease of 9% from the second quarter of 2014
• Added 5 gross (0.17 net) wells, increasing our total producing well count to 291 gross (8.96 net), an increase of 43% over the second quarter of 2014
• Recorded $3.6 million of adjusted EBITDA, equal to the EBITDA generated in the second quarter of 2014
• Reduced general and administrative expenses to $7.15 per Boe, a decrease of 27% from the second quarter of 2014
• Recorded GAAP net loss for the quarter of $0.39 per diluted share, impacted by a non-cash impairment of $21.6 million ($0.34 per diluted share, net of tax effect)
• Announced the formation of a strategic partnership with Merced Capital, focused on acquiring non-operated assets in the Williston Basin
• Continued the development of the Teton project (1.76 net wells) with strong initial production rates
• During and subsequent to the second quarter, entered into swap contracts to sell an additional 237,000 barrels of oil at a weighted average price of $60.40.

Teton Project Update and Production Guidance

The drilling, completion and flowback of the Teton project is running ahead of the Company's original plan, and the daily production volumes achieved during the flowback phase were higher than our initial estimates. The transition from flowback to full production will occur after all of the Teton wells are connected to permanent production facilities, and at this stage, the natural gas tie-in is running behind schedule. While we are very encouraged by the production rates achieved during flowback, we are not updating our full year production guidance of 1,200 Boe/d until we receive clarity on the timing of the facility completion.

The following table summarizes the flowback status of the Teton project as of August 10, 2015. The operator's flowback procedure limited production to less than 15,000 barrels of oil per well. Flowback commenced in late June and is expected to end on approximately August 15.

Management Comment

"The Company is excited by the initial results from our Teton project and we look forward to full production and cash flow from this asset," said Ken DeCubellis, Chief Executive Officer. "We added additional hedges in May and July to protect our balance sheet, maintain ample cash flow and preserve our asset value during this down cycle in oil prices. As we look forward to the remainder of 2015 and 2016, the Company's focus will be on allocating our free cash flow to debt reduction and finding acquisition opportunities for our joint venture with Merced."

Liquidity Position and Borrowing Base

Black Ridge ended the quarter with $29.75 million drawn on its $34 million senior secured revolving credit facility. The next redetermination date is scheduled for October 1, 2015. The Company expects to fund 2015 development from availability under the borrowing base and cash flow from operations.

Hedging Update

In the second quarter of 2015, the Company realized an $847,198 gain on settled derivatives, and a $1,956,155 unrealized loss on mark-to-market adjustments to its outstanding derivatives contracts. As of June 30, 2015, the Company's net derivative asset was $5,990,919. On July 22, 2015, the Company entered into new crude oil swap contracts for 18,000 barrels in 2H 2016 at $55.55, 42,000 barrels in 2017 at $57.95 and 96,000 barrels at $60.67 in 2018. The following table summarizes the Company's open crude oil swap contracts as of August 12, 2015:

In addition to the open crude oil swap contracts, the Company has entered into costless collar contracts. The costless collars are used to establish floor and ceiling prices on anticipated crude oil production. There were no premiums paid or received by us related to the costless collar contracts. The following table reflects open costless collar crude oil contracts as of August 12, 2015:

2015 Operating and Financial Results

The following table presents selected operating and financial data for the periods indicated.

Dahl Federal Recognition

During the second quarter of 2015, the Company recognized all well costs, revenues, and expenses related to the Dahl Federal 2-15H well back to the inception of the well in January of 2012. Due to uncertainties regarding the Company's ownership of this interest related to the State of North Dakota's claim to mineral rights under the Missouri River, the Company had not previously recognized any well costs, revenues, or expenses for this well. As these uncertainties are now resolved, in the second quarter of 2015, the Company recognized $1.3 million of oil and gas revenues, $83,000 of production expenses, $140,000 of production taxes, and production of 15,682 net Boe from prior periods. The Company also capitalized $0.9 million of well costs related to the drilling and completion of the well. Please see the Company's 10-Q filing for additional information.

Second Quarter 2015 Financial Results

In the second quarter of 2015, oil and gas sales, excluding the impact of settled derivatives, were $5.05 million, a decrease of 9% as compared to the second quarter of 2014. The Company realized an average price of $54.71 per barrel of oil and $1.66 per mcf of gas, representing decreases of 40% and 67%, respectively, as compared to the second quarter of 2014. The impact of weaker commodity prices was partially offset by a 57% increase in production over the second quarter of 2014. The Company's production in the second quarter of 2015 was comprised of 88% oil and 12% natural gas and natural gas liquids, on a Boe basis.

For the second quarter of 2015, the Company realized a gain on settled derivatives of $0.8 million, compared to a loss of $0.3 million in the second quarter of 2014. The Company had a mark-to-market derivative loss of $2.0 million in the second quarter of 2015 compared to a mark-to-market loss of $0.9 million in the second quarter of 2014.

Production expenses for the second quarter of 2015 were $1.2 million, or $11.29 per Boe, compared to $0.6 million, or $9.15 per Boe, for the second quarter of 2014. The increase in production expense in the second quarter was primarily attributable to cleanout costs on producing wells subsequent to completion activities on offset locations in the Company's Stockyard Creek project.

Production taxes for the second quarter of 2015 were $0.6 million, compared to $0.6 million, for the second quarter of 2014. Production taxes as a percent of revenue were 11.0% for the second quarter of 2015, compared to 10.7% for the second quarter of 2014.

Depletion, depreciation, amortization and accretion ("DD&A") was $2.9 million, or $28.87 per Boe, in the second quarter of 2015, compared to $2.1 million, or $32.97 per Boe, in the second quarter of 2014.

As a result of the currently prevailing low commodity prices and their effect on the proved reserve values of properties in 2015, we recorded a non-cash ceiling test impairment of $21.6 million in the second quarter of 2015. The Company did not have any impairment of its proved oil and gas properties in the second quarter of 2014. The impairment charge affected our reported net income but did not reduce our cash flow.

General and administrative expenses ("G&A") for the second quarter of 2015 were $0.7 million, or $7.15 per Boe, compared to $0.6 million, or $9.75 per Boe, for the second quarter of 2014. Cash G&A (non-GAAP, excludes stock-based compensation expense) was $0.6 million, or $5.65 per Boe, for the second quarter of 2015 compared to $0.5 million, or $7.52 per Boe, for the second quarter of 2014.

Interest expense, net of capitalized interest, was $1.6 million in the second quarter of 2015, compared to $1.3 million in the second quarter of 2014. The increase in interest expense was primarily due to additional borrowing to fund the Company's capital development program.

The income tax benefit recognized during the second quarter of 2015 was $6.0 million, or 24.2% of the loss before income taxes, as compared to a net income tax benefit of $0.3 million, or 36.0% of the loss before income taxes, in the second quarter of 2014. The lower effective tax rate in 2015 relates to a valuation allowance placed on the net deferred tax asset in the second quarter of 2015.

The Company recorded $3.6 million of adjusted EBITDA in the second quarter of 2015, flat compared to the second quarter of 2014. Adjusted EBITDA is a non-GAAP financial measure. Please refer to the reconciliation in this release for additional information about this measure.

Acreage and Drilling

As of June 30, 2015, the Company controlled approximately 8,600 net acres in the Williston Basin. Approximately 72% of the acreage is held by production with 291 gross (8.96 net) wells producing. Additionally, the Company had 2.04 net wells in development as of June 30, 2015.

Producing Wells

The following table sets forth wells in which Black Ridge holds a participating interest that were completed, acquired, or first recognized during the quarter ending June 30, 2015:

"Drilling" Wells

The following table sets forth wells in which Black Ridge holds a participating interest that were either preparing to drill, drilling, awaiting completion or completing as of June 30, 2015:

Adjusted Net Loss and Adjusted EBITDA

In addition to reporting net loss as defined under GAAP, we also present Adjusted Net Loss and Adjusted EBITDA. We define Adjusted Net Loss as net loss, excluding (i) net income (loss) on the mark-to-market of derivatives, net of tax and (ii) impairment of oil and gas properties, net of tax. We define Adjusted EBITDA as earnings (loss) before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion and amortization, (iv) impairment of oil and gas properties, (v) accretion of abandonment liability, (vi) income (losses) on the mark-to-market of derivatives, and (vii) non-cash expenses relating to share based payments recognized under ASC Topic 718. We believe the use of non-GAAP financial measures provides useful information to investors regarding our current financial performance; however, Adjusted Net Loss and Adjusted EBITDA do not represent, and should not be considered alternatives to GAAP measurements. We believe these measures are useful in evaluating our fundamental core operating performance. Specifically, we believe the non-GAAP Adjusted Net Loss and Adjusted EBITDA results provide useful information to both management and investors by excluding certain income and expenses that our management believes are not indicative of our core operating results. Although we use Adjusted Net Loss and Adjusted EBITDA to manage our business, including the preparation of our annual operating budget and financial projections, we believe that non-GAAP financial measures have limitations and do not reflect all of the amounts associated with our results of operations as determined in accordance with GAAP and that these measures should only be used to evaluate our results of operations in conjunction with the corresponding GAAP financial measures. A reconciliation of Adjusted Net Loss and Adjusted EBITDA to net loss, GAAP, is included below:

Reconciliation of Net Loss to Adjusted Net Loss

Reconciliation of Net Loss to Adjusted EBITDA

 

Our Adjusted EBITDA for the three and six month periods ending June 30, 2015 includes income from the Dahl Federal 2-15H well recognized in the current period from activity in prior periods of $1,040,397 and $1,027,995, respectively.

 

 

Cautionary Statement as to Forward-Looking Statements

Certain statements contained herein, which are not historical, are forward-looking statements that are subject to risks and uncertainties not known or disclosed herein that could cause actual results to differ materially from those expressed herein. These statements may include projections and other "forward-looking statements" within the meaning of the federal securities laws. Any such projections or statements reflect management's current views about future events and financial performance. No assurances can be given that such events or performance will occur as projected and actual results may differ materially from those projected. Important factors that could cause the actual results to differ materially from those projected include, without limitation, general economic or industry conditions nationally and/or in the communities in which our Company conducts business, volatility in commodity prices for crude oil and natural gas, environmental risks, legislation or regulatory requirements, conditions of the securities markets, our ability to raise capital or have access to debt financing, changes in accounting principles, policies or guidelines, financial or political instability, acts of war or terrorism, increases in operator costs, other economic, competitive, governmental, regulatory and technical factors affecting our Company's operations, products, services and prices and other risks inherent in the Company's businesses that are detailed in the Company's Securities and Exchange Commission ("SEC") filings. Readers are encouraged to review these risks in the Company's SEC filings.

About the Company

Black Ridge Oil & Gas is an oil and gas exploration and production company based in Minnetonka, Minnesota. Black Ridge's focus is exclusive to the Williston Basin Bakken and Three Forks trend in North Dakota and Montana. For additional information, visit the Company's website at www.blackridgeoil.com.

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Contact
Black Ridge Oil & Gas, Inc.

Ken DeCubellis, Chief Executive Officer
952-426-1241

www.blackridgeoil.com

 

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SOURCE Black Ridge Oil & Gas, Inc.