Black Ridge Oil & Gas Announces Second Quarter 2015 Results

Aug 13, 2015, 16:05 ET from Black Ridge Oil & Gas, Inc.

MINNETONKA, Minn., Aug. 13, 2015 /PRNewswire/ -- Black Ridge Oil & Gas, Inc. ("the Company") (OTCQB: 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.

WELL

W.I.

Current Status

Flowback Information

Bbls Oil Produced

MCF Gas Produced

# of Days

Teton 2-8-10MBH

8.4%

Flowback Complete, Waiting on Facilities

14,839

24,020

6

Teton 6-8-10MBH

8.4%

Flowback Complete, Waiting on Facilities

14,656

27,510

6

Teton 7-8-10MBH

8.4%

Flowback Complete, Waiting on Facilities

14,785

22,171

7

Teton 8-8-10TFSH

8.4%

Flowback Complete, Waiting on Facilities

14,789

21,645

7

Teton 5-1-3TFSH

8.4%

Flowback Complete, Waiting on Facilities

14,732

16,173

8

Teton 6-8-10TFSH

8.4%

Flowback Complete, Waiting on Facilities

14,883

23,203

8

Teton 5-8-10MBH

8.4%

Flowback Complete, Waiting on Facilities

14,280

21,591

8

Teton 7-1-3TFSH

8.4%

Flowback Complete, Waiting on Facilities

14,835

25,283

8

Kings Canyon 6-1-27MBH

8.4%

Flowback Complete, Waiting on Facilities

14,699

10,225

9

Kings Canyon 7-8-34MBH

8.4%

Flowback Complete, Waiting on Facilities

14,805

28,901

9

Teton 3-8-10MBH

8.4%

Flowback Complete, Waiting on Facilities

14,861

23,839

9

Kings Canyon 2-8-34UTFH

8.4%

Flowback Complete, Waiting on Facilities

14,224

14,066

11

Kings Canyon 4-8-34UTFH

8.4%

Flowback Complete, Waiting on Facilities

14,696

19,730

11

Kings Canyon 6-8-34UTFH

8.4%

Flowback Complete, Waiting on Facilities

14,087

25,180

11

Kings Canyon 4-1-27MTFH

8.4%

Flowback Complete, Waiting on Facilities

14,691

11,371

11

Kings Canyon 4-8-34MBH

8.4%

Flowback Complete, Waiting on Facilities

12,806

16,552

12

Kings Canyon 5-8-34UTFH

8.4%

Flowback Complete, Waiting on Facilities

14,764

17,500

12

Kings Canyon 6-1-27MTFH

8.4%

Flowback in Process

11,391

13,050

8

Kings Canyon 3-1-27MTFH

8.4%

Flowback in Process

9,701

14,606

11

RemingTeton 8-8-10 MBH

6.3%

Flowback Complete, Waiting on Facilities

14,805

20,641

7

TetoNorman 1-1-3UTFH

6.3%

Flowback Complete, Waiting on Facilities

14,736

16,696

9

LaCanyon 8-8-34MBH

2.1%

Flowback Complete, Waiting on Facilities

14,794

25,880

7

DeKing 1-8-34MBH-ULW

2.1%

Flowback Complete, Waiting on Facilities

14,713

22,758

9

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:



Oil


Weighted Average

Term


(barrels)


Price ($ per Bbl)

2015:





Q3


21,750


89.84

Q4


57,750


72.40

2016:





Q1


43,500


75.84

Q2


43,500


75.84

Q3


30,000


79.47

Q4


30,000


79.47

2017:





Q1


30,000


76.95

Q2


30,000


76.95

Q3


30,000


76.95

Q4


30,000


76.95

2018:





Q1


24,000


60.67

Q2


24,000


60.67

Q3


24,000


60.67

Q4


24,000


60.67

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:



Oil


Floor/Ceiling



Term


(Barrels)


Price (WTI)


Basis

Costless Collars – Crude Oil







07/01/2015 – 12/31/2015


18,000


$75.00/$95.60


NYMEX

01/01/2016 – 06/30/2016


10,002


$80.00/$89.50


NYMEX

2015 Operating and Financial Results

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


Three Months Ended


Six Months Ended


June 30,


June 30,


2015


2014


2015


2014

Net Production:












Oil (Bbl)


90,118



58,812



163,041



101,967

Natural gas (Mcf)


72,381



37,482



170,695



61,819

Barrel of oil equivalent (Boe)


102,182



65,059



191,490



112,270













Average Sales Prices:












Oil (per Bbl)

$

54.71


$

91.27


$

47.06


$

89.88

Effect of oil hedges on average price (per Bbl)

$

9.40


$

(4.47)


$

12.15


$

(3.71)

Oil net of hedging (per Bbl)

$

64.11


$

86.80


$

59.21


$

86.17

Natural gas (per Mcf)

$

1.66


$

4.97


$

1.55


$

6.78

Realized price, net of settled derivatives (Boe)

$

57.71


$

81.33


$

51.79


$

81.99













Average Production Costs:












Oil (per Bbl)

$

12.50


$

9.79


$

12.68


$

9.85

Natural gas (per Mcf)

$

0.38


$

0.53


$

0.45


$

0.75

Barrel of oil equivalent (Boe)

$

11.29


$

9.15


$

11.19


$

9.36














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:

Well

Operator

Location

WI(1)

Dahl Federal 2-15H

SM Energy

McKenzie, ND

8.7%

Tetonorman 1-1-3UTFH ULW

Burlington Resources

McKenzie, ND

6.3%

DeKing 1-8-34MBH-ULW

Burlington Resources

McKenzie, ND

2.1%

P Jackman 156-100-2-18-6-1H

Whiting

Williams, ND

1.0%

P Jackman 156-100-2-18-6-2H

Whiting

Williams, ND

1.0%

CCU North Coast 31-25TFH

Burlington Resources

Dunn, ND

0.8%


(1)The working interests are based on Black Ridge's internal records and may be subject to change by operators' third-party legal counsel in preparing final division order title opinions for each well.

"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:


Well

Operator

Location

WI(1)

Kings Canyon 5-8-34UTF

Burlington Resources

McKenzie, ND

8.4%

Teton 5-8-10MBH

Burlington Resources

McKenzie, ND

8.4%

Kings Canyon 6-1-27MBH

Burlington Resources

McKenzie, ND

8.4%

Kings Canyon 6-1-27MTFH

Burlington Resources

McKenzie, ND

8.4%

Kings Canyon 4-1-27MTFH

Burlington Resources

McKenzie, ND

8.4%

Kings Canyon 3-1-27MTFH

Burlington Resources

McKenzie, ND

8.4%

Kings Canyon 6-8-34UTFH

Burlington Resources

McKenzie, ND

8.4%

Kings Canyon 2-8-34UTFH

Burlington Resources

McKenzie, ND

8.4%

Kings Canyon 4-8-34UTFH

Burlington Resources

McKenzie, ND

8.4%

Kings Canyon 4-8-34MBH

Burlington Resources

McKenzie, ND

8.4%

Teton 5-1-3TFSH

Burlington Resources

McKenzie, ND

8.4%

Teton 2-8-10MBH

Burlington Resources

McKenzie, ND

8.4%

Teton 3-8-10MBH

Burlington Resources

McKenzie, ND

8.4%

Teton 6-8-10TFSH

Burlington Resources

McKenzie, ND

8.4%

Teton 8-8-10TFSH

Burlington Resources

McKenzie, ND

8.4%

Teton 7-8-10MBH

Burlington Resources

McKenzie, ND

8.4%

Teton 6-8-10MBH

Burlington Resources

McKenzie, ND

8.4%

Teton 7-1-3TFSH

Burlington Resources

McKenzie, ND

8.4%

Kings Canyon 7-8-34MBH

Burlington Resources

McKenzie, ND

8.4%

Remingteton 8-8-10MBH

Burlington Resources

McKenzie, ND

6.2%

Thorp Federal 11X-28A

XTO

Dunn, ND

3.4%

LaCanyon 8-8-34MBH ULW

Burlington Resources

McKenzie, ND

2.1%

EN-Weyrauch B-LW-154-93-3031H-1

Hess

Mountrail, ND

1.6%

P Berger 156-100-14-7-6-4H

Whiting

Williams, ND

1.0%

P Berger 156-100-14-7-6-3H

Whiting

Williams, ND

1.0%

Aaberg 8-5N-1H

Mountain Divide

Divide, ND

0.8%

CCU Powell 41-29TFH

Burlington Resources

Dunn, ND

0.8%

CCU Dakotan 2-7-17MBH

Burlington Resources

Dunn, ND

0.8%

CCU Dakotan 1-7-17TFH

Burlington Resources

Dunn, ND

0.8%

CCU Dakotan 1-7-17MBH

Burlington Resources

Dunn, ND

0.8%

CCU Dakotan 2-7-17TFH

Burlington Resources

Dunn, ND

0.8%

CCU Dakotan 5-8-17TFH

Burlington Resources

Dunn, ND

0.8%

CCU Dakotan 6-8-17MBH

Burlington Resources

Dunn, ND

0.8%

CCU Dakotan 7-8-17TFH

Burlington Resources

Dunn, ND

0.8%

CCU Dakotan 7-8-17MBH

Burlington Resources

Dunn, ND

0.8%

CCU Dakotan 5-8-17MBH

Burlington Resources

Dunn, ND

0.8%

CCU Dakotan 4-8-17TFH

Burlington Resources

Dunn, ND

0.8%

CCU Dakotan 3-8-17MBH

Burlington Resources

Dunn, ND

0.8%

CCU Gopher 1-2-15TFH

Burlington Resources

Dunn, ND

0.8%

CCU Gopher 2-2-15MBH

Burlington Resources

Dunn, ND

0.8%

CCU Red River 7-2-15TFH

Burlington Resources

Dunn, ND

0.8%

CCU Red River 8-2-15MBH

Burlington Resources

Dunn, ND

0.8%

CCU Bison Point 24-34TFH

Burlington Resources

Dunn, ND

0.8%

CCU Bison Point 24-34MBH

Burlington Resources

Dunn, ND

0.8%

CCU Bison Point 34-34TFH

Burlington Resources

Dunn, ND

0.8%

CCU Bison Point 34-34MBH

Burlington Resources

Dunn, ND

0.8%

CCU Olympian 21-2MBH

Burlington Resources

Dunn, ND

0.8%

CCU Olympian 31-2TFH

Burlington Resources

Dunn, ND

0.8%

CCU Olympian 31-2MBH

Burlington Resources

Dunn, ND

0.8%

CCU Golden Creek 34-23TFH

Burlington Resources

Dunn, ND

0.8%

CCU Burner 31-26TFH

Burlington Resources

Dunn, ND

0.8%

Jersey 1-6H

Continental

Mountrail, ND

0.8%

Jersey 3-6H1

Continental

Mountrail, ND

0.8%

Jersey 2-6H2

Continental

Mountrail, ND

0.8%

Jersey 5-6H

Continental

Mountrail, ND

0.8%

P Johnson 153-98-1-6-7-16H

Whiting

Williams, ND

0.6%

P Johnson 153-98-1-6-7-16HA

Whiting

Williams, ND

0.6%

P Pankowski 153-98-4-6-7-13H

Whiting

Williams, ND

0.6%

P Pankowski 153-98-4-6-7-13HA

Whiting

Williams, ND

0.6%

Burr Federal 10-26H

Continental

Mountrail, ND

0.5%

Burr Federal 9-26H1

Continental

Mountrail, ND

0.5%

Burr Federal 11-26H

Continental

Mountrail, ND

0.5%

Burr Federal 12-26H1

Continental

Mountrail, ND

0.5%

Burr Federal 13-26H

Continental

Mountrail, ND

0.5%

Burr Federal 14-26H

Continental

Mountrail, ND

0.5%


(1)The working interests are based on Black Ridge's internal records and may be subject to change by operators' third-party legal counsel in preparing final division order title opinions for each well.

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


Three Months Ended


Six Months Ended


June 30,


June 30,


2015


2014


2015


2014

Net loss

$

(18,669,638)


$

(543,360)


$

(19,942,574)


$

(924,920)

Add back:












Loss on mark-to-market of derivatives, net of tax (a)


1,467,155



555,124



1,191,826



690,159

Impairment of oil and gas properties, net of tax (b)


16,229,000



-



16,229,000



-

Adjusted net income (loss)

$

(973,483)


$

11,764


$

(2,521,748)


$

(234,761)













Weighted average common shares outstanding - basic and fully diluted


47,979,990



47,979,990



47,979,990



47,979,990













Net income (loss) per common share – basic and fully diluted

$

(0.39)


$

(0.01)


$

(0.42)


$

(0.02)

Add:












Change due to loss on mark-to- market of derivatives, net of tax


0.03



0.01



0.03



0.01

Change due to impairment of oil and gas properties, net of tax


0.34



-



0.34



-

Adjusted net income (loss) per common share – basic and fully diluted

$

(0.02)


$

0.00


$

(0.05)


$

(0.01)


(a)Adjusted to reflect tax expense, computed based on our effective tax rate of approximately 25% in 2015 and 37% in 2014, of $489,000 and $326,000 for the three month ended June 30, 2015 and 2014, respectively, and $397,000 and $405,000 for the six months ended June 30, 2015 and 2014, respectively.


(b)Adjusted to reflect tax expense, computed based on our effective tax rate of approximately 25% in 2015 and 37% in 2014, of $5,410,000 and $-0- for the three month ended June 30, 2015 and 2014, respectively, and $5,410,000 and $-0- for the six months ended June 30, 2015 and 2014, respectively.

Reconciliation of Net Loss to Adjusted EBITDA

Black Ridge Oil & Gas, Inc.

Reconciliation of Adjusted EBITDA

(Unaudited)



Three Months Ended


Six Months Ended


June 30,


June 30,


2015


2014


2015


2014

Net income (loss)

$     (18,669,638)


$    (543,360)


$     (19,942,574)


$      (924,920)

Add back:








Interest expense, net, excluding amortization of warrant based financing costs

1,385,837


1,136,603


2,792,657


2,065,981

Income tax provision

(5,957,649)


(305,715)


(6,593,040)


(589,738)

Depreciation, depletion, and amortization

2,941,753


2,139,733


5,576,052


3,734,590

Impairment of oil and gas properties

21,639,000


-


21,639,000


-

Accretion of abandonment liability

7,932


5,148


15,861


9,653

Share based compensation

314,162


301,241


635,514


599,003

Loss on mark-to market of derivatives

1,956,154


881,124


1,588,826


1,095,159









Adjusted EBITDA

$        3,617,551


$  3,614,774


$        5,712,296


$    5,989,728

 

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.


BLACK RIDGE OIL & GAS, INC.

CONDENSED BALANCE SHEETS










June 30,


December 31,


2015


2014

ASSETS

(Unaudited)







Current assets:




Cash and cash equivalents

$    214,583


$          94,682

Derivative instruments, current

3,007,135


3,571,803

Accounts receivable

4,091,371


5,740,171

Prepaid expenses

46,351


41,387

Total current assets

7,359,440


9,448,043





Property and equipment:




Oil and natural gas properties, full cost method of accounting:




Proved properties

124,205,553


112,418,105

Unproved properties

1,258,138


591,121

Other property and equipment

139,004


139,004

Total property and equipment

125,602,695


113,148,230

Less, accumulated depreciation, amortization, depletion and allowance for impairment

(46,117,576)


(18,902,524)

Total property and equipment, net

79,485,119


94,245,706





Derivative instruments, long-term

2,983,784


4,007,942

Debt issuance costs, net

510,239


701,019





Total assets

$90,338,582


$ 108,402,710









LIABILITIES AND STOCKHOLDERS' EQUITY








Current liabilities:




Accounts payable

$10,166,181


$   10,291,262

Accrued expenses

91,155


57,435

Total current liabilities

10,257,336


10,348,697





Asset retirement obligations

344,360


286,804

Revolving credit facilities and long term debt, net of discounts of $1,665,862 and $2,072,483, respectively

60,026,143


51,834,603

Deferred tax liability

-


6,593,040





Total liabilities

70,627,839


69,063,144





Commitments and contingencies

-


-





Stockholders' equity:




Preferred stock, $0.001 par value, 20,000,000 shares authorized, no shares issued and outstanding

-


-

Common stock, $0.001 par value, 500,000,000 shares authorized, 47,979,990 shares issued and outstanding

47,980


47,980

Additional paid-in capital

33,965,465


33,651,714

Retained earnings (accumulated deficit)

(14,302,702)


5,639,872

Total stockholders' equity

19,710,743


39,339,566





Total liabilities and stockholders' equity

$90,338,582


$ 108,402,710






 


BLACK RIDGE OIL & GAS, INC.

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)










For the Three Months


For the Six Months


Ended June 30,


Ended June 30,


2015


2014


2015


2014









Oil and gas sales

$ 5,050,080


$5,553,997


$ 7,936,536


$9,584,417

Gain (loss) on settled derivatives

847,198


(262,719)


1,980,619


(378,882)

Loss on the mark-to-market of derivatives

(1,956,155)


(881,124)


(1,588,826)


(1,095,159)

Total revenues

3,941,123


4,410,154


8,328,329


8,110,376









Operating expenses:








Production expenses

1,153,663


595,591


2,143,520


1,103,054

Production taxes

555,152


591,525


841,344


996,832

General and administrative

730,445


634,109


1,540,453


1,404,882

Depletion of oil and gas properties

2,937,744


2,131,545


5,567,776


3,718,477

Impairment of oil and gas properties

21,639,000


-


21,639,000


-

Accretion of discount on asset retirement obligations

7,932


5,148


15,861


9,653

Depreciation and amortization

4,009


8,188


8,276


16,113

Total operating expenses

27,027,945


3,966,106


31,756,230


7,249,011









Net operating income (loss)

(23,086,822)


444,048


(23,427,901)


861,365









Other income (expense):








Other income

6,707


-


6,707


-

Interest (expense)

(1,547,172)


(1,293,123)


(3,114,420)


(2,376,023)

Total other income (expense)

(1,540,465)


(1,293,123)


(3,107,713)


(2,376,023)









Loss before provision for income taxes

(24,627,287)


(849,075)


(26,535,614)


(1,514,658)









Provision for income taxes

5,957,649


305,715


6,593,040


589,738









Net loss

$(18,669,638)


$(543,360)


$(19,942,574)


$(924,920)

















Weighted average common shares outstanding - basic

47,979,990


47,979,990


47,979,990


47,979,990

Weighted average common shares outstanding - fully diluted

47,979,990


47,979,990


47,979,990


47,979,990









Net loss per common share - basic

$          (0.39)


$      (0.01)


$          (0.42)


$      (0.02)

Net loss per common share - fully diluted

$          (0.39)


$      (0.01)


$          (0.42)


$      (0.02)

 


BLACK RIDGE OIL & GAS, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)










For the Six Months


Ended June 30,


2015


2014

CASH FLOWS FROM OPERATING ACTIVITIES




Net loss

$(19,942,574)


$ (924,920)

Adjustments to reconcile net income (loss)




to net cash provided by operating activities:




Depletion of oil and gas properties

5,567,776


3,718,477

Depreciation and amortization

8,276


16,113

Amortization of debt issuance costs

190,780


145,307

Accretion of discount on asset retirement obligations

15,861


9,653

Loss on the mark-to-market of derivatives

1,588,826


1,095,159

Accrued payment in kind interest applied to long term debt

634,919


472,712

Amortization of original issue discount on debt

84,858


60,288

Amortization of debt discounts, warrants

321,763


310,042

Common stock options issued to employees and directors

313,751


288,961

Deferred income taxes

(6,593,040)


(589,738)

Impairment of oil and natural gas properties

21,639,000


-

Decrease (increase) in current assets:




Accounts receivable

1,648,800


(2,835,328)

Prepaid expenses

(4,964)


(15,812)

Increase (decrease) in current liabilities:




Accounts payable

36,328


203,177

Accrued expenses

33,720


58,040

Net cash provided by operating activities

5,544,080


2,012,131





CASH FLOWS FROM INVESTING ACTIVITIES




Proceeds from sale or swap of oil and gas properties

103,000


1,360,920

Purchases of oil and gas properties and development capital expenditures

(12,677,179)


(11,731,981)

Advances to operators

-


(3,491,089)

Purchases of other property and equipment

-


(11,131)

Net cash used in investing activities

(12,574,179)


(13,873,281)





CASH FLOWS FROM FINANCING ACTIVITIES




Advances from revolving credit facilities and long term debt

10,600,000


18,700,000

Repayments on revolving credit facilities

(3,450,000)


(7,850,000)

Debt issuance costs

-


(54,782)

Net cash provided by financing activities

7,150,000


10,795,218





NET CHANGE IN CASH

119,901


(1,065,932)

CASH AT BEGINNING OF PERIOD

94,682


1,150,347

CASH AT END OF PERIOD

$      214,583


$      84,415









SUPPLEMENTAL INFORMATION:




Interest paid

$   2,174,153


$ 1,457,540

Income taxes paid

$                  -


$                -





NON-CASH INVESTING AND FINANCING ACTIVITIES:




Net change in accounts payable for purchase of oil and gas properties

$    (161,409)


$    (98,778)

Advances to operators applied to development of oil and gas properties

$                  -


$ 2,131,043

Capitalized asset retirement costs, net of revision in estimate

$        41,695


$      40,712

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

 

SOURCE Black Ridge Oil & Gas, Inc.



RELATED LINKS

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