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Company News

Black Ridge Oil & Gas Announces Third Quarter 2014 Results and Issues Fourth Quarter 2014 Average Production Guidance of 950 to 1,100 Boe per day

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MINNETONKA, Minn., Nov. 12, 2014 /PRNewswire/ -- Black Ridge Oil & Gas, Inc. ("the Company") (OTCQB: ANFC), a growth-oriented exploration and production (E&P) company focused on non-operated Bakken and Three Forks properties, today announced financial and operating results for the quarter ended September 30, 2014.

Third Quarter 2014 Highlights

  • Record quarterly production averaged 761 barrels of oil equivalent per day ("Boe/d"), representing 147% year over year and 6% sequential quarter over quarter growth
  • The Company recorded adjusted EBITDA of $3.6 million in the third quarter of 2014, an increase of 114% compared to adjusted EBITDA of $1.7 million in the third quarter of 2013 and equaling our record $3.6 million in the second quarter of 2014
  • Participated in the development and start-up of five gross (0.62 net) Mandaree wells in EOG's Antelope Extension prospect
  • Drilling activity commenced on the Company's 22 gross well (1.37 net) Teton project, production expected in mid-2015
  • Increased borrowing base on senior-secured credit facility from $20 million to $35 million. The facility carries interest rates of LIBOR + 3% to LIBOR + 3.50%. Availability as of September 30, 2014 was $17.25 million
  • As of September 30, 2014, the Company was participating in an additional 65 gross (1.61 net) wells that were preparing to drill, drilling, awaiting completion or completing

Fourth Quarter 2014 Guidance

  • The Company anticipates fourth quarter 2014 average production between 950 to 1,100 Boe/d
  • Black Ridge has 45,000 barrels of oil hedged for the fourth quarter at an average price of $94.49
  • As of October 31, 2014, the Company was participating in an additional 86 gross (2.48 net) wells that were preparing to drill, drilling, awaiting completion or completing

Management Comment

"The third quarter of 2014 was another excellent quarter for the Company. Despite planned shut-ins for additional well completions in the Stockyard Creek prospect, we were still able to achieve a production record." commented Black Ridge's Chief Executive Officer Ken DeCubellis. "As we look to the remainder of 2014 and into 2015, the five gross (0.62 net) well Mandaree prospect in EOG's prolific Antelope area of McKenzie County began producing at the tail end of the third quarter of 2014 and will be the main driver for growth in the fourth quarter. We expect fourth quarter production to average between 950 and 1,100 Boe/d net to the Company. In this environment of lower oil prices the Company is maintaining a disciplined, return driven approach to investments. Our Mandaree and Teton projects are expected to exceed our hurdle rate of 30% IRR at current oil prices."

Mandaree Update

The following table summarizes initial results in the Mandaree Project operated by EOG Resources, Inc. The Company has a 12.5% working interest in each well:

Well Name

Bench/Target Formation

Initial Production Rate

Mandaree 17-05H

Three Forks – 1st Bench

2,212 Boe/d

Mandaree 135-05H

Three Forks – 2nd Bench

2,037 Boe/d

Mandaree 134-05H

Three Forks – 3rd Bench

1,777 Boe/d

Mandaree 28-05H

Middle Bakken

Confidential

Mandaree 110-05H

Middle Bakken

Confidential

Third Quarter 2014 Operating and Financial Results

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



Three Months Ended







September 30,







2014



2013



% Change


Net Production:













Oil (Bbl)



62,603




26,427




137


Natural Gas (Mcf)



44,639




11,535




287


Barrel of Oil Equivalent (Boe)



70,043




28,349




147


Average Daily Production (Boe/d)



761




308




147















Average Sales Prices:













Oil (per Bbl)


$

84.17



$

96.07




(12)


Effect of oil hedges on average price (per Bbl)


$

(1.12)



$

(0.80)






Oil net of hedging (per Bbl)


$

83.05



$

95.27




(13)


Natural Gas (per Mcf)


$

4.99



$

6.41




(22)


Effect of natural gas hedges on average price (per Mcf)


$



$






Natural gas net of hedging (per Mcf)


$

4.99



$

6.41




(22)















Per Boe including settled derivatives


$

77.41



$

91.41




(15)















Operating Expenses (per Boe):













Production Expenses


$

9.57



$

9.69




(1)


Production Taxes


$

8.41



$

9.56




(12)


G&A Expense


$

9.85



$

18.51




(47)


Depletion, Depreciation, Amortization and Accretion


$

32.69



$

37.83




(14)


Third Quarter 2014 Operational Results

Production for the third quarter of 2014 totaled 70 thousand barrels of oil equivalent ("MBoe"), averaging a record 761 Boe/d, representing 147% growth over the third quarter of 2013 and 6% growth over the second quarter of 2014 on a Boe/d basis. Production growth in the quarter was limited by shut-ins for offset completions in the Stockyard Creek prospect.

Throughout the third quarter of 2014, the Company participated in the completion of 24 gross (1.08 net) wells compared to 11 gross (0.40 net) wells in the third quarter of 2013. Well additions were driven primarily by the completion of the five gross (0.62 net) Mandaree wells in the final days of the quarter.

As of September 30, 2014, the Company had participated in a total of 231 gross (7.36 net) producing wells compared to 92 gross (3.22 net) producing wells in the third quarter of 2013, representing an increase of 129% on a net well basis.

In addition to the 7.36 net producing wells, the Company owned working interests in 65 gross (1.61 net) wells that were preparing to drill, drilling, awaiting completion, or completing as of September 30, 2014.

The Company controlled approximately 10,000 net mineral acres prospective for the Bakken and Three Forks formations in North Dakota and eastern Montana as of September 30, 2014.

Third Quarter 2014 Financial Results

Oil and gas sales, which exclude the effect of derivatives, totaled $5.5 million for the third quarter of 2014, representing 110% growth over the third quarter of 2013 and a 1% decline from the second quarter of 2014. The decline from the second quarter of 2014 was driven primarily by lower average realized oil prices.

For the third quarter of 2014, the Company realized a loss on settled derivatives of $0.1 million. The Company realized a non-cash mark-to-market gain on unsettled derivatives of $2.1 million.

For the third quarter of 2014, the Company's realized oil price was $84.17 per barrel of oil before the effect of settled derivatives. The Company's realized price was 14% per barrel below the NYMEX WTI benchmark in the third quarter of 2014. For the third quarter of 2014, the Company's realized price for natural gas, including natural gas liquids, was $4.99 per MCF, representing a 22% decrease compared to $6.41 per MCF in the third quarter of 2013. The realized price on a per BOE basis, including settled derivatives, was $77.41, a decrease of 15% compared to the third quarter of 2013 and a decrease of 5% compared to the second quarter of 2014.

Production expenses increased to $670 thousand in the third quarter of 2014 compared to $275 thousand in the third quarter of 2013, driven primarily by the Company's production growth. On a per unit basis, this equated to a 1% decrease in production expenses to $9.57/Boe in the third quarter of 2014 from $9.69/Boe in the third quarter of 2013.

Production taxes increased to $589 thousand in the third quarter of 2014 from $271 thousand in the third quarter of 2013, driven primarily by increased production. For the third quarter of 2014, production taxes averaged 10.7% of oil and gas sales compared to 10.4% for the third quarter of 2013.

General and administrative ("G&A") expenses increased to $690 thousand for the third quarter of 2014 from $525 thousand for the third quarter of 2013. On a per Boe basis, G&A expenses averaged $9.85/Boe for the third quarter of 2014, representing a 47% decrease from $18.51/Boe in the third quarter of 2013 and an increase of 1% from $9.75/Boe in the second quarter of 2014.

Depletion, depreciation, amortization, and accretion ("DD&A") totaled $2.3 million in the third quarter of 2014, an increase of 113% as compared to $1.1 million in the third quarter of 2013. Depletion expense, the largest component of DD&A, was $32.49/Boe in the third quarter of 2014, representing a decrease of 14% as compared to $37.56/Boe in the third quarter of 2013.

Interest expense in the third quarter of 2014 totaled $1.4 million as compared to $0.7 million in the third quarter of 2013. The increase was primarily driven by increased borrowings as the Company financed acquisitions and well development.

Income tax expense in the third quarter of 2014 was $0.7 million as compared to an income tax benefit of $0.1 million in the same period in 2013.

The Company reported net income attributable to common stockholders of $1.2 million, or $0.02 per basic and diluted common share for the third quarter of 2014 as compared to a net loss of $0.2 million, or ($0.00) per basic and diluted common share for the third quarter of 2013.

The Company recorded adjusted EBITDA of $3.6 million in the third quarter of 2014, an increase of 114% compared to adjusted EBITDA of $1.7 million in the third quarter of 2013 and equaling our record $3.6 million in 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.

Liquidity Position

The Company ended the third quarter of 2014 with $47.8 million drawn on its Senior and Subordinate Credit Facilities. As of September 30, 2014, total availability under the two facilities was $65 million following the redetermination of the Senior Credit Facility borrowing base from $20 million to $35 million in August. The Company expects the next redetermination of the Senior Credit Facility borrowing base in April 2015. The Company expects to fund future development through operating cash flow and additional borrowings from the existing credit facilities.

Hedging Update

The following table summarizes our derivative contracts as of September 30, 2014, by fiscal quarter:



Swaps



Costless Collars


Contract period


Volume (Bbls)



Weighted

Average Price

(per Bbl)



Volume (Bbls)



Weighted

Average

Floor/Ceiling

Price (per Bbl)

2014:















  Q4



45,000



$

94.49






-

2015:















  Q1



21,750



$

89.84




9,000



$75.00 – $95.60

  Q2



21,750



$

89.84




9,000



$75.00 – $95.60

  Q3



21,750



$

89.84




9,000



$75.00 – $95.60

  Q4



21,750



$

89.84




9,000



$75.00 – $95.60

2016:















  Q1



21,000



$

89.73




5,001



$80.00 – $89.50

  Q2



21,000



$

89.73




5,001



$80.00 – $89.50

  Q3



21,000



$

89.73






-

  Q4



21,000



$

89.73






-

2017:














-

  Q1



19,500



$

87.18






-

  Q2



19,500



$

87.18






-

  Q3



19,500



$

87.18






-

  Q4



19,500



$

87.18






-

Well Update:

Producing Wells: The following table sets forth Bakken and Three Forks wells in which Black Ridge holds a participating interest that were completed or acquired during the quarter ending September 30, 2014.

Well

Operator

Location

WI(1)

Mandaree 110-05H

EOG

McKenzie, ND

12.5%

Mandaree 134-05H

EOG

McKenzie, ND

12.5%

Mandaree 135-05H

EOG

McKenzie, ND

12.5%

Mandaree 17-05H

EOG

McKenzie, ND

12.5%

Mandaree 28-05H

EOG

McKenzie, ND

12.5%

Bootleg 4-14-15TFH

Slawson

Williams, ND

11.4%

Bootleg 5-14-15TFH

Slawson

Williams, ND

11.4%

Wallace 1-6H

Continental

Williams, ND

8.5%

Gladys 1-20H

Continental

Williams, ND

2.0%

Miller 157-101-12D-1-3H

Halcon

Williams, ND

1.1%

Miller 157-101-12D-1-4H

Halcon

Williams, ND

1.1%

CCU Corral Creek 11-28MBH

Burlington Resources

Dunn, ND

0.8%

CCU Corral Creek 21-28TFH

Burlington Resources

Dunn, ND

0.8%

CCU Corral Creek 31-28MBH

Burlington Resources

Dunn, ND

0.8%

CCU Corral Creek 31-28TFH

Burlington Resources

Dunn, ND

0.8%

CCU Four Aces 24-21MBH

Burlington Resources

Dunn, ND

0.8%

CCU Four Aces 24-21TFH

Burlington Resources

Dunn, ND

0.8%

CCU Four Aces 34-21MBH

Burlington Resources

Dunn, ND

0.8%

CCU Four Aces 34-21TFH

Burlington Resources

Dunn, ND

0.8%

CCU Olympian 11-2MBH

Burlington Resources

Dunn, ND

0.8%

CCU Olympian 21-2TFH

Burlington Resources

Dunn, ND

0.8%

CCU Olympian 44-35MBH

Burlington Resources

Dunn, ND

0.8%

CCU Olympian 44-35TFH

Burlington Resources

Dunn, ND

0.8%

Bock Federal 44-7PH

Whiting

Stark, ND

0.6%


(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 Bakken and Three Forks wells in which Black Ridge holds a participating interest that are either preparing to drill, drilling, awaiting completion or completing as of September 30, 2014.

Well

Operator

Location

WI(1)

Bootleg 6-14-15TFH

Slawson

Williams, ND

11.4%

Bootleg 7-14-15TFH

Slawson

Williams, ND

11.3%

Bootleg 8-14-15TF2H

Slawson

Williams, ND

11.3%

Matilda Bay 1-15H

Slawson

Williams, ND

10.0%

Rainbow 10-19-18HBK

Samson Oil and Gas

Williams, ND

10.0%

Billabong 2-13-14HBK

Slawson

Williams, ND

7.5%

McCracken 2758 21-10 5B

Oasis

Roosevelt, MT

7.1%

McCracken 2758 44-9 4B

Oasis

Roosevelt, MT

7.1%

McCracken 2758 34-9 3B

Oasis

Roosevelt, MT

7.1%

McCracken 2758 41-10 6B

Oasis

Roosevelt, MT

7.1%

Teton 5-1-3TFSH

Burlington Resources

McKenzie, ND

6.2%

Kings Canyon 6-8-34UTFH

Burlington Resources

McKenzie, ND

6.2%

Ironbank 4-14-13TFH

Slawson

Williams, ND

5.4%

Ironbank 5-14-13TFH

Slawson

Williams, ND

5.4%

Ironbank 6-14-13TFH

Slawson

Williams, ND

5.4%

Ironbank 7-14-13TFH

Slawson

Williams, ND

5.4%

Revolver 7-35H

Slawson

Mountrail, ND

1.6%

Little Muddy 10TFH

Triangle

Williams, ND

0.9%

CCU Powell 41-29TFH

Burlington Resources

Dunn, ND

0.8%

CCU Olympian 11-2TFH

Burlington Resources

Dunn, ND

0.8%

CCU Pullman 2-8-7MBH

Burlington Resources

Dunn, ND

0.8%

CCU Pullman 8-8-7TFH

Burlington Resources

Dunn, ND

0.8%

CCU Pullman 7-8-7MBH

Burlington Resources

Dunn, ND

0.8%

Jersey 23-6H1

Continental

Mountrail, ND

0.8%

Jersey 25-6H

Continental

Mountrail, ND

0.8%

Jersey 26-6H2

Continental

Mountrail, ND

0.8%

Jersey 27-6H1

Continental

Mountrail, ND

0.8%

Jersey 28-6H3

Continental

Mountrail, ND

0.8%

Jersey 29-6XH

Continental

Mountrail, ND

0.8%

CCU Powell 41-29MBH

Burlington Resources

Dunn, ND

0.8%

CCU Pullman 6-8-7MBH

Burlington Resources

Dunn, ND

0.8%

CCU Pullman 1-8-7TFH

Burlington Resources

Dunn, ND

0.8%

CCU Pullman 3-8-7TFH

Burlington Resources

Dunn, ND

0.8%

CCU Pullman 3-8-7MBH

Burlington Resources

Dunn, ND

0.8%

CCU Pullman 5-8-7TFH

Burlington Resources

Dunn, ND

0.8%

CCU Pullman 5-8-7MBH

Burlington Resources

Dunn, ND

0.8%

CCU Pullman 6-8-7TFH

Burlington Resources

Dunn, ND

0.8%

CCU Pullman 7-8-7TFH

Burlington Resources

Dunn, ND

0.8%

CCU Golden Creek 44-23MBH

Burlington Resources

Dunn, ND

0.8%

Jersey 1-6H

Continental

Mountrail, ND

0.8%

Jersey 3-6H1

Continental

Mountrail, ND

0.8%

Jersey 7-6H1

Continental

Mountrail, ND

0.8%

Jersey 6-6H2

Continental

Mountrail, ND

0.8%

Jersey 24-6H3

Continental

Mountrail, ND

0.8%

Aaberg 8-5N-1H

Mountain Divide

Divide, ND

0.8%

CCU North Coast 21-25TFH

Burlington Resources

Dunn, ND

0.8%

CCU North Coast 31-25MBH

Burlington Resources

Dunn, ND

0.8%

CCU North Coast 4-8-23MBH

Burlington Resources

Dunn, ND

0.8%

CCU North Coast 41-25MBH

Burlington Resources

Dunn, ND

0.8%

CCU North Coast 4-8-23TFH

Burlington Resources

Dunn, ND

0.8%

CCU Golden Creek 44-23TFH

Burlington Resources

Dunn, ND

0.8%

CCU North Coast 41-25TFH

Burlington Resources

Dunn, ND

0.8%

CCU Main Streeter 24-24TFH

Burlington Resources

Dunn, ND

0.8%

CCU Main Streeter 14-24MBH

Burlington Resources

Dunn, ND

0.8%

Jersey 2-6H2

Continental

Mountrail, ND

0.8%

Jersey 8-6H3

Continental

Mountrail, ND

0.8%

Jersey 5-6H

Continental

Mountrail, ND

0.8%

Jersey 4-6H3

Continental

Mountrail, ND

0.8%

Oakdale 2-13H1

Continental

Dunn, ND

0.6%

Ryden 3-24H

Continental

Dunn, ND

0.6%

Ryden 2-24AH1

Continental

Dunn, ND

0.6%

Oakdale 5-13H

Continental

Dunn, ND

0.6%

Oakdale 3-13H

Continental

Dunn, ND

0.6%

Oakdale 4-13H1

Continental

Dunn, ND

0.6%

Ryden 4-24H1

Continental

Dunn, ND

0.6%


(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.







Non-GAAP Financial Measures

In addition to reporting net income (loss) as defined under GAAP, we also present Adjusted Net Income (Loss) and Adjusted EBITDA. We define Adjusted Net Income (Loss) as net income, excluding net losses on the mark-to-market of derivatives, net of tax. We define Adjusted EBITDA as net income before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion and amortization, (iv) accretion of abandonment liability, (v) losses on the mark-to-market of derivatives, and (vi) 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 Income (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 Income (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 Income (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 Income (Loss) and Adjusted EBITDA to Net Income, GAAP, is included below:

 


Black Ridge Oil & Gas, Inc.

Reconciliation of Adjusted Net Income (Loss)

(Unaudited)




Three Months Ended



Nine Months Ended




September 30,



September 30,




2014



2013



2014



2013


Net Income (Loss)


$

1,190,716



$

(223,664)



$

265,796



$

(207,151)


Add back:

















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



(1,352,798)




29,225




(663,639)




29,225


Adjusted Net Income (Loss)


$

(162,082)



$

(194,439)



$

(397,843)



$

(177,926)



















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



49,588,039




47,979,990




49,824,437




47,979,990



















Net income (loss) per common share – basic


$

0.02



$

(0.00)



$

0.01



$

(0.00)


Subtract:

















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



(0.03)




0.00




(0.01)




0.00


Adjusted Net Income (loss) per common share – basic


$

(0.00)



$

(0.00)



$

(0.01)



$

(0.00)



















Net income (loss) per common share - fully diluted



0.02




(0.00)




0.01



$

0.00


Subtract:

















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



(0.03)




0.00




(0.01)




0.00


Adjusted Net Income (Loss) per common share - fully diluted


$

(0.00)



$

(0.00)



$

(0.01)



$

(0.00)


_____________________________

(a)Adjusted to reflect tax expense (benefit), computed based on our effective tax rate of approximately 37%, of $795,000 and $(17,000) for the three months ended September 30, 2014 and 2013, respectively, and $389,000 and ($17,000) for the nine months ended September 30, 2014 and 2013, respectively.

 

Black Ridge Oil & Gas, Inc.

Reconciliation of Adjusted EBITDA

(Unaudited)




Three Months Ended



Nine Months Ended



September 30,



September 30,



2014


2013


2014


2013

Net Income (loss)


$

1,190,716


$

(223,664)


$

265,796


$

(207,151)

Add Back:













Interest Expense, net, excluding amortization













of warrant based financing costs



1,280,674



622,842



3,346,655



1,365,898

Income Tax Provision



700,587



(88,708)



110,849



(615,409)

Depreciation, Depletion, and Amortization



2,283,917



1,070,753



6,018,507



2,650,763

Accretion of Abandonment Liability



5,833



1,811



15,486



4,774

Share Based Compensation



302,961



263,379



901,964



658,977

Loss (gain) on mark-to market of derivatives



(2,147,798)



46,225



(1,052,639)



46,225














Adjusted EBITDA


$

3,616,890


$

1,692,638


$

9,606,618


$

3,904,077

Financial and Statistical Data Tables

Following are the financial highlights for the comparative three and nine month periods ended September 30, 2014 and 2013. The following information is based on GAAP reported earnings, with additional required disclosures included in the Company's Form 10-Q:

BLACK RIDGE OIL & GAS, INC.

CONDENSED BALANCE SHEETS




September 30,



December 31,




2014



2013


ASSETS


(Unaudited)















Current assets:









Cash and cash equivalents


$

28,239



$

1,150,347


Derivative instruments



287,421





Accounts receivable



3,139,049




1,905,467


Advances to operators



2,656,697




1,214,662


Prepaid expenses



72,058




26,142


Total current assets



6,183,464




4,296,618











Property and equipment:









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









Proved properties



104,227,772




79,361,432


Unproved properties



2,151,044




2,798,795


Other property and equipment



126,613




115,482


Total property and equipment



106,505,429




82,275,709


Less, accumulated depreciation, amortization, depletion and

allowance for impairment



(15,531,941)




(9,513,434)


Total property and equipment, net



90,973,488




72,762,275











Derivative instruments



551,542





Debt issuance costs, net



797,341




772,883











Total assets


$

98,505,835



$

77,831,776











LIABILITIES AND STOCKHOLDERS' EQUITY


















Current liabilities:









Accounts payable


$

12,484,201



$

8,453,709


Accrued expenses



66,236




4,813


Current portion of derivative instruments






139,065


Total current liabilities



12,550,437




8,597,587











Derivative instruments






74,611


Asset retirement obligations



237,966




160,665


Revolving credit facilities and long term debt, net of discounts of $2,274,346

and $2,645,582, respectively



46,464,881




30,556,301


Deferred tax liability



4,144,694




4,033,845











Total liabilities



63,397,978




43,423,009











Commitments and contingencies (See note 15)
















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



33,506,089




33,072,795


Retained earnings



1,553,788




1,287,992


Total stockholders' equity



35,107,857




34,408,767











Total liabilities and stockholders' equity


$

98,505,835



$

77,831,776


 

BLACK RIDGE OIL & GAS, INC.

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)




For the Three Months



For the Nine Months




Ended September 30,



Ended September 30,




2014



2013



2014



2013















Oil and gas sales


$

5,492,326



$

2,612,640



$

15,076,743



$

6,674,940


Loss on settled derivatives



(70,253)




(21,184)




(449,135)




(21,184)


Gain (loss) on the mark-to-market of

derivatives



2,147,798




(46,225)




1,052,639




(46,225)


Total revenues



7,569,871




2,545,231




15,680,247




6,607,531



















Operating expenses:

















Production expenses



670,404




274,756




1,773,458




813,023


Production taxes



588,923




271,116




1,585,755




722,986


General and administrative



690,189




524,849




2,095,071




1,715,287


Depletion of oil and gas properties



2,275,703




1,064,921




5,994,180




2,633,309


Accretion of discount on asset

  retirement obligations



5,833




1,811




15,486




4,774


Depreciation and amortization



8,214




5,832




24,327




17,454


Total operating expenses



4,239,266




2,143,285




11,488,277




5,906,833



















Net operating income



3,330,605




401,946




4,191,970




700,698



















Other income (expense):

















Interest income



972




148




972




341


Interest (expense)



(1,440,274)




(714,466)




(3,816,297)




(1,523,599)


Total other income (expense)



(1,439,302)




(714,318)




(3,815,325)




(1,523,258)



















Income (loss) before provision for

income taxes



1,891,303




(312,372)




376,645




(822,560)



















Provision for income taxes



(700,587)




88,708




(110,849)




615,409



















Net income (loss)


$

1,190,716



$

(223,664)



$

265,796



$

(207,151)




































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



49,588,039




47,979,990




49,824,437




47,979,990



















Net income (loss) per common share – basic


$

0.02



$

(0.00)



$

0.01



$

(0.00)


Net income (loss) per common share - fully diluted


$

0.02



$

(0.00)



$

0.01



$

(0.00)


 

BLACK RIDGE OIL & GAS, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)




For the Nine Months




Ended September 30,




2014



2013


CASH FLOWS FROM OPERATING ACTIVITIES









Net income (loss)


$

265,796



$

(207,151)


Adjustments to reconcile net income (loss) to net cash provided by

operating activities:









Depletion of oil and gas properties



5,994,180




2,633,309


Depreciation and amortization



24,327




17,454


Amortization of debt issuance costs



229,936




691,928


Accretion of discount on asset retirement obligations



15,486




4,774


Loss (gain) on the mark-to-market of derivatives



(1,052,639)




46,225


Accrued payment in kind interest applied to long term debt



787,344




36,667


Amortization of original issue discount on debt



102,566




6,457


Amortization of debt discounts, warrants



468,670




49,170


Common stock warrants granted as financing costs






108,190


Common stock options issued to employees and directors



433,294




501,617


Deferred income taxes



110,849




(615,409)


Decrease (increase) in current assets:









Accounts receivable



(1,233,582)




(1,288,026)


Prepaid expenses



(45,916)




16,364


Increase (decrease) in current liabilities:









Accounts payable



223,779




(216,975)


Accrued expenses



61,423




35,250


Net cash provided by operating activities



6,385,513




1,819,844











CASH FLOWS FROM INVESTING ACTIVITIES









Proceeds from sale or swap of oil and gas properties



1,360,920




500,031


Purchases of oil and gas properties and development capital expenditures



(17,410,744)




(5,991,601)


Advances to operators



(5,742,272)




(882,604)


Purchases of other property and equipment



(11,131)




(1,301)


Net cash used in investing activities



(21,803,227)




(6,375,475)











CASH FLOWS FROM FINANCING ACTIVITIES









Advances from revolving credit facilities and long term debt



24,150,000




22,000,000


Repayments on revolving credit facilities



(9,600,000)




(13,048,844)


Debt issuance costs



(254,394)




(725,887)


Net cash provided by financing activities



14,295,606




8,225,269











NET CHANGE IN CASH



(1,122,108)




3,669,638


CASH AT BEGINNING OF PERIOD



1,150,347




1,417,340


CASH AT END OF PERIOD


$

28,239



$

5,086,978











SUPPLEMENTAL INFORMATION:









Interest paid


$

2,411,463



$

551,399


Income taxes paid


$



$











NON-CASH INVESTING AND FINANCING ACTIVITIES:









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


$

3,821,375



$

2,277,913


Advances to operators paid in swap for oil and gas properties


$



$

(1,200,000)


Advances to operators applied to development of oil and gas properties


$

4,285,575



$

2,212,323


Capitalized asset retirement costs, net of revision in estimate


$

61,815



$

10,400


Fair value of detachable warrants granted in consideration of debt financing


$



$

2,473,576


 

Upcoming Conference Presentation Schedule

Black Ridge Oil & Gas plans to present at the following energy conferences and investor events:

SeeThruEquity Microcap Investor Conference
November 12, 2014
Convene Midtown East, New York, NY

Midwest Investment Conference
November 18, 2014
Cleveland Convention Center, Cleveland, OH

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 Black Ridge Oil & Gas 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 Black Ridge Oil & Gas

Black Ridge Oil & Gas is a growth-oriented 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. Black Ridge Oil & Gas controls approximately 10,000 net acres prospective for Bakken and/or Three Forks development. For additional information, visit the Company's website at www.blackridgeoil.com.

To receive timely information on Black Ridge Oil & Gas when it hits the newswire, sign up for Black Ridge's email news alert system today at https://ir.stockpr.com/blackridgeoil/email-alerts.

Contact:

Ken DeCubellis
Chief Executive Officer
952-426-1241
ken.decubellis@blackridgeoil.com

SOURCE Black Ridge Oil & Gas, Inc.