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Company News

Black Ridge Oil & Gas Announces First Quarter 2015 Results

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MINNETONKA, Minn., May 14, 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 months ended March 31, 2015.

First Quarter 2015 Company Highlights

  • Quarterly production increased 89% over the first quarter of 2014 to 89.3 thousand barrels of oil equivalent ("MBoe"), an average of approximately 992 barrels of oil equivalent per day ("Boe/d")
  • Oil and gas sales totaled $2.9 million, a decrease of 28% from the first quarter of 2014
  • Participated in the completion of 39 gross (0.91 net) wells, increasing our total producing well count to 286 gross (8.79 net), an increase of 60% over the first quarter of 2014
  • Recorded $2.1 million of adjusted EBITDA, representing a decrease of 12% from the first quarter of 2014
  • Reduced general and administrative expenses to $9.07 per Boe, a decrease of 44% from the first quarter of 2014
  • Increased full year 2015 production guidance from an average of 1,100 BOEPD to 1,200 BOEPD

Acreage and Drilling

As of March 31, 2015, the Company controlled approximately 9,400 net acres in the Williston Basin. Approximately 67% of the acreage is held by production with 286 gross (8.79 net) wells producing. Additionally, the Company had 2.2 net wells in development as of March 31, 2015.

Management Comment

Ken DeCubellis, Black Ridge's CEO, commented, "While the commodity price environment was challenging during the first quarter of 2015, we are generally pleased with the underlying performance of our asset base. The Company was able to achieve our second highest average production on record in the first quarter despite lower than expected volume in Stockyard Creek as wells were shut in for offset completion activities. As we look forward to the balance of 2015, we are cautiously optimistic as we have seen oil prices improve by over 20%, as compared to the average in the first quarter, and we have received indications from our operating partners that drilling and completion costs will be lower than the assumptions used in our 2015 capital plan. However, we are not changing our original 2015 development plan, with the cornerstone being our 1.76 net well Teton project, which is currently scheduled to commence production during the second half of 2015. Any incremental cash flow above our original 2015 plan will be used to reduce debt and build additional liquidity."

Teton Project Update and Production Guidance

The 23 gross well, 1.76 net well, Teton project continues development per plan. All of the wells in this project have finished the drilling phase and completions will begin in the coming weeks. Based on the Company's current expectation for total drilling and completion costs, estimated ultimate recoveries, and the current commodity price deck, the Teton project is expected to meet or exceed our 30% IRR investment hurdle. The Company is increasing our full year production guidance from an average of 1,100 BOEPD to 1,200 BOEPD. We anticipate our production levels to be below the full year average until the Teton project is online, at which point our daily production volumes will exceed the full year average.

DeCubellis added, "The Company has taken some risk to participate in the Teton project during this phase of the commodity price cycle. We are excited about the current pace of the project's development, our current view of the overall economics of the project, and most importantly, the significant improvement that the project will bring to the Company's balance sheet once in full production. As such, we have recently taken the opportunity to hedge additional volume from October 2015 through June 2016."

Liquidity Position and Borrowing Base

Black Ridge ended the quarter with $25.95 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 first quarter of 2015, the Company realized a $1,133,421 gain on settled derivatives and a $367,329 unrealized gain on mark-to-market adjustments to its outstanding derivatives contracts. As of March 31, 2015, the Company's net derivative asset was $7,947,074. On May 11, 2015, the Company entered into new swap contracts for 36,000 barrels in Q4 2015 at $61.87 and 45,000 barrels in 1H 2016 at $62.88. The following table summarizes the Company's open crude oil swap contracts as of May 12, 2015:



Oil


Weighted Average

Term


(barrels)


Price ($ per Bbl)

2015:





Q2


21,750


89.84

Q3


21,750


89.84

Q4


57,750


72.40

2016:





Q1


43,500


75.84

Q2


43,500


75.84

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

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 May 12, 2015:



Oil


Floor/Ceiling



Term


(Barrels)


Price (WTI)


Basis

Costless Collars – Crude Oil







04/01/2015 – 12/31/2015


27,000


$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




March 31,




2015


2014


% Change

Net Production:








Oil (Bbl)


72,922



43,155


69

Natural gas (Mcf)


98,314



24,337


304

Barrel of oil equivalent (Boe)


89,308



47,211


89

Average daily production (Boe/d)


992



525


89









Average Sales Prices:








Oil (per Bbl)

$

37.60


$

87.99


(57)

Effect of oil hedges on average price (per Bbl)

$

15.55


$

(2.69)



Oil net of hedging (per Bbl)

$

53.15


$

85.30


(38)

Natural gas (per Mcf)

$

1.47


$

9.58


(85)

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

$

-


$

-



Natural gas net of hedging (per Mcf)

$

1.47


$

9.58


(85)









Per Boe including settled derivatives

$

45.01


$

82.91


(46)









Operating Expenses (per Boe):








Production expenses

$

11.08


$

10.75


3

Production taxes

$

3.20


$

8.59


(63)

G&A expense

$

9.07


$

16.33


(44)

Depletion, depreciation, amortization and accretion

$

29.59


$

33.88


(13)

First Quarter 2015 Financial Results

In the first quarter of 2015, oil and gas sales, excluding the impact of settled derivatives, were $2.89 million, a decrease of 28% as compared to the first quarter of 2014. The Company realized an average price of $37.60 per barrel of oil and $1.47 per mcf of gas, representing decreases of 57% and 85%, respectively, as compared to the first quarter of 2014. The impact of weaker commodity prices was partially offset by an 89% increase in production over the first quarter of 2014.

The Company's production in the first quarter of 2015 was comprised of 82% oil and 18% natural gas and natural gas liquids, on a Boe basis. The Company's increased gas sales percentage reflects the continued improvement in gas infrastructure in North Dakota and higher gas production in the Company's current areas of focus.

Lease operating expenses for the first quarter of 2015 were $1.0 million, or $11.08 per Boe, compared to $0.5 million, or $10.75 per Boe, for the first quarter of 2014. The increase in lease operating expense in the first quarter was primarily attributable to cleanout costs on producing wells subsequent to completion activities on offset locations in the Company's Stockyard Creek project.

General and administrative expenses ("G&A") for the first quarter of 2015 were $0.8 million, or $9.07 per Boe, compared to $0.8 million, or $16.33 per Boe for the first quarter of 2014. Cash G&A (non-GAAP, excludes stock-based compensation expense) was $0.6 million, or $7.27 per Boe, for the first quarter of 2015 compared to $0.6 million, or $13.27 per Boe for the first quarter of 2014.

The Company recorded $2.1 million of adjusted EBITDA in the first quarter of 2015, representing a decrease of 12% from $2.4 million of adjusted EBITDA in the first 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.

Producing Wells

The following table sets forth wells in which Black Ridge holds a participating interest that were completed or acquired during the quarter ending March 31, 2015:

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%

Billabong 2-13-14HBK

Slawson

Williams, ND

7.5%

Ironbank 4-14-13TFH

Slawson

Williams, ND

5.5%

Ironbank 7-14-13TFH

Slawson

Williams, ND

5.4%

Ironbank 6-14-13TFH

Slawson

Williams, ND

5.4%

EN-VP AND R- 154-94-2536H-1

Hess

Mountrail, ND

3.1%

EN-VP AND R- 154-94-2536H-2

Hess

Mountrail, ND

3.1%

EN-VP AND R- 154-94-2536H-3

Hess

Mountrail, ND

3.1%

EN-VP AND R- 154-94-2536H-4

Hess

Mountrail, ND

3.1%

Duletski Federal 14-12PH

Whiting

Billings, ND

0.8%

CCU Main Streeter 24-24TFH

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 North Coast 4-8-23MBH

Burlington Resources

Dunn, ND

0.8%

CCU North Coast 31-25MBH

Burlington Resources

Dunn, ND

0.8%

CCU North Coast 41-25TFH

Burlington Resources

Dunn, ND

0.8%

CCU Pullman 1-8-7TFH

Burlington Resources

Dunn, ND

0.8%

CCU Pullman 2-8-7MBH

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 6-8-7MBH

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%

CCU Pullman 7-8-7TFH

Burlington Resources

Dunn, ND

0.8%

CCU Golden Creek 44-23TFH

Burlington Resources

Dunn, ND

0.8%

CCU Golden Creek 44-23MBH

Burlington Resources

Dunn, ND

0.8%

CCU Main Streeter 14-24MBH

Burlington Resources

Dunn, 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.

"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 March 31, 2015:

Well

Operator

Location

WI(1)

Rainbow 10-19-18HBK

Samson Oil and Gas

Williams, ND

10.0%

Kings Canyon 5-8-34UTF

Burlington Resources

McKenzie, ND

8.4%

Teton 5-8-10MBH

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%

Kings Canyon 4-1-27MTFH

Burlington Resources

McKenzie, ND

8.4%

Teton 5-1-3TFSH

Burlington Resources

McKenzie, ND

8.4%

Teton 3-8-10MBH

Burlington Resources

McKenzie, ND

8.4%

Teton 2-8-10MBH

Burlington Resources

McKenzie, ND

8.4%

Teton 6-8-10TFSH

Burlington Resources

McKenzie, ND

8.4%

Teton 6-8-10MBH

Burlington Resources

McKenzie, ND

8.4%

Kings Canyon 6-1-27MBH

Burlington Resources

McKenzie, ND

8.4%

Teton 8-8-10TFSH

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%

Kings Canyon 6-8-34UTFH

Burlington Resources

McKenzie, ND

8.4%

Teton 7-8-10MBH

Burlington Resources

McKenzie, ND

8.4%

Kings Canyon 6-1-27MTFH

Burlington Resources

McKenzie, ND

8.4%

Kings Canyon 3-1-27MTFH

Burlington Resources

McKenzie, ND

8.4%

Tetonorman 1-1-3UTFH ULW

Burlington Resources

McKenzie, ND

6.3%

Remingteton 8-8-10MBH

Burlington Resources

McKenzie, ND

6.2%

Thorp Federal 11X-28A

XTO

Dunn, ND

3.4%

DeKing 1-8-34MBH-ULW

Burlington Resources

McKenzie, ND

2.1%

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 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%

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

Kodiak

Williams, ND

1.0%

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

Kodiak

Williams, ND

1.0%

Gobbler 6-35-26TFH

Slawson

Mountrail, ND

0.8%

Aaberg 8-5N-1H

Mountain Divide

Divide, ND

0.8%

CCU Dakotan 3-8-17MBH

Burlington Resources

Dunn, ND

0.8%

CCU Powell 41-29TFH

Burlington Resources

Dunn, ND

0.8%

CCU North Coast 31-25TFH

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 Red River 7-2-15TFH

Burlington Resources

Dunn, ND

0.8%

CCU Red River 8-2-15MBH

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%

Jersey 1-6H

Continental

Mountrail, ND

0.8%

Jersey 5-6H

Continental

Mountrail, ND

0.8%

Jersey 3-6H1

Continental

Mountrail, ND

0.8%

Jersey 2-6H2

Continental

Mountrail, ND

0.8%

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

Kodiak

Williams, ND

0.6%

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

Kodiak

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 net  income (loss) on the mark-to-market of derivatives, net of tax. We define Adjusted EBITDA as earnings (loss) before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion and amortization, (iv) accretion of abandonment liability, (v) income (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 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


March 31,


2015


2014

Net loss

$

(1,272,936)


$

(381,560)

Add back:






Losses (gains) on the mark-to-market of derivatives, net of tax (a)


(246,239)



134,835

Adjusted net loss

$

(1,519,175)


$

(246,725)







Weighted average common shares outstanding - basic


47,979,990



47,979,990

Weighted average common shares outstanding - fully diluted


47,979,990



47,979,990







Net loss per common share - basic

$

(0.03)


$

(0.01)

Add:






Change due to losses (gains) on the mark-to-market of derivatives, net of tax


-



-

Adjusted net loss per common share - basic

$

(0.03)


$

(0.01)







Net income (loss) per common share - fully diluted


(0.03)


$

(0.01)

Add:






Change due to losses (gains) on the mark-to-market of derivatives, net of tax


-



-

Adjusted net loss per common share - fully diluted

$

(0.03)


$

(0.01)


(a)Adjusted to reflect tax benefit (expense), computed based on our effective tax rate of approximately 33% in 2015 and 37% in 2014, of ($121,000) and $79,200 for the three months ended March 31, 2015 and 2014, respectively.

 


Reconciliation of Net Loss to Adjusted EBITDA



Three Months Ended


March 31,


2015


2014

Net loss

$

(1,272,936)


$

(381,560)

Add back:




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

1,406,820


929,378

Income tax provision

(635,391)


(284,023)

Depreciation, depletion, and amortization

2,634,299


1,594,857

Accretion of abandonment liability

7,929


4,505

Share based compensation

321,352


297,762

Unrealized gain (loss) on the mark-to-market of derivatives

(367,328)


214,035





Adjusted EBITDA

$

2,094,745


$

2,374,954

 


BLACK RIDGE OIL & GAS, INC.

CONDENSED BALANCE SHEETS










March 31,


December 31,


2015


2014

ASSETS

 (Unaudited)







Current assets:




Cash and cash equivalents

$         97,781


$         94,682

Derivative instruments

3,863,912


3,571,803

Accounts receivable

3,420,230


5,740,171

Prepaid expenses

38,243


41,387

Total current assets

7,420,166


9,448,043





Property and equipment:




Oil and natural gas properties, full cost method of accounting




Proved properties

118,421,670


112,418,105

Unproved properties

2,168,117


591,121

Other property and equipment

139,004


139,004

Total property and equipment

120,728,791


113,148,230

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

(21,536,823)


(18,902,524)

Total property and equipment, net

99,191,968


94,245,706





Derivative instruments

4,083,162


4,007,942

Debt issuance costs, net

604,697


701,019





Total assets

$111,299,993


$108,402,710









LIABILITIES AND STOCKHOLDERS' EQUITY








Current liabilities:




Accounts payable

$  11,014,273


$  10,291,262

Accrued expenses

68,416


57,435

Total current liabilities

11,082,689


10,348,697





Asset retirement obligations

330,557


286,804

Revolving credit facility and long term debt, net of discounts of $1,869,656 and $2,072,483, respectively

55,701,544


51,834,603

Deferred tax liability

5,957,649


6,593,040





Total liabilities

73,072,439


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

33,812,638


33,651,714

Retained earnings

4,366,936


5,639,872

Total stockholders' equity

38,227,554


39,339,566





Total liabilities and stockholders' equity

$111,299,993


$108,402,710





 


BLACK RIDGE OIL & GAS, INC.

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)










For the Three Months


Ended March 31,


2015


2014





Oil and gas sales

$  2,886,456


$ 4,030,420

Gain (loss) on settled derivatives

1,133,421


(116,163)

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

367,329


(214,035)

Total revenues

$  4,387,206


$ 3,700,222





Operating expenses:




Production expenses

989,857


507,463

Production taxes

286,192


405,307

General and administrative

810,008


770,773

Depletion of oil and gas properties

2,630,032


1,586,932

Accretion of discount on asset retirement obligations

7,929


4,505

Depreciation and amortization

4,267


7,925

Total operating expenses

4,728,285


3,282,905





Net operating income (loss)

(341,079)


417,317





Other income (expense):




Interest (expense)

(1,567,248)


(1,082,900)

Total other income (expense)

(1,567,248)


(1,082,900)





Loss before provision for income taxes

(1,908,327)


(665,583)





Provision for income taxes

635,391


284,023





Net loss

$(1,272,936)


$ (381,560)









Weighted average common shares outstanding - basic

47,979,990


47,979,990

Weighted average common shares outstanding - fully diluted

47,979,990


47,979,990





Net loss per common share - basic

$        (0.03)


$       (0.01)

Net loss per common share - fully diluted

$        (0.03)


$       (0.01)





 


BLACK RIDGE OIL & GAS, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)










For the Three Months


Ended March 31,


2015


2014

CASH FLOWS FROM OPERATING ACTIVITIES




Net loss

$(1,272,936)


$(381,560)

Adjustments to reconcile net loss to net cash provided by operating activities:




Depletion of oil and gas properties

2,630,032


1,586,932

Depreciation and amortization

4,267


7,925

Amortization of debt issuance costs

96,322


70,653

Accretion of discount on asset retirement obligations

7,929


4,505

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

(367,329)


214,035

Accrued payment in kind interest applied to long term debt

314,114


208,803

Amortization of original issue discount on debt

42,399


26,316

Amortization of debt discounts, warrants

160,428


153,522

Common stock options issued to employees and directors

160,924


144,240

Deferred income taxes

(635,391)


(284,023)

Decrease (increase) in current assets:




Accounts receivable

2,319,941


(1,160,467)

Prepaid expenses

3,144


(8,444)

Increase (decrease) in current liabilities:




Accounts payable

110,460


252,259

Accrued expenses

10,981


42,271

Net cash provided by operating activities

3,585,285


876,967





CASH FLOWS FROM INVESTING ACTIVITIES




Proceeds from sale of oil and gas properties

99,000


1,234,740

Purchases of oil and gas properties and development capital expenditures

(7,031,186)


(7,582,458)

Advances to operators

-


(1,410,896)

Purchases of other property and equipment

-


(8,094)

Net cash used in investing activities

(6,932,186)


(7,766,708)





CASH FLOWS FROM FINANCING ACTIVITIES




Advances from revolving credit facilities and long term debt

5,700,000


9,350,000

Repayments on revolving credit facilities

(2,350,000)


(3,550,000)

Net cash provided by financing activities

3,350,000


5,800,000





NET CHANGE IN CASH

3,099


(1,089,741)

CASH AT BEGINNING OF PERIOD

94,682


1,150,347

CASH AT END OF PERIOD

$       97,781


$    60,606









SUPPLEMENTAL INFORMATION:




Interest paid

$  1,110,083


$  640,978

Income taxes paid

$                -


$              -





NON-CASH INVESTING AND FINANCING ACTIVITIES:




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

$     612,551


$(846,354)

Advances to operators applied to purchase of oil and gas properties

$                -


$  321,904

Capitalized asset retirement costs, net of revision in estimate

$       35,824


$    23,259





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

 

To view the original version on PR Newswire, visit:http://www.prnewswire.com/news-releases/black-ridge-oil--gas-announces-first-quarter-2015-results-300083632.html

SOURCE Black Ridge Oil & Gas, Inc.