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Company News

Black Ridge Oil & Gas Announces 2014 Fourth Quarter and Full Year Results

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MINNETONKA, Minn., March 30, 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 and year ended December 31, 2014.

2014 Company Highlights

  • Annual production increased 168% to 291.8 thousand barrels of oil equivalent ("MBoe"), an average of approximately 799 barrels of oil equivalent per day ("Boe/d")
  • Oil and gas sales increased 127% to $21.1 million
  • Total proved reserves increased 18% to 5.4 MMBoe
  • Pre-tax PV-10% of the total proved reserves as of December 31, 2014 increased 35% to $100.3 million
  • Ended 2014 with production from 247 gross (7.88 net) wells, up from 153 gross (4.87 net) at the end of 2013, an increase of 62% on a net well basis
  • Recorded $14.4 million of adjusted EBITDA, representing an increase of 145% from 2013
  • Fourth quarter production increased to 1,190 Boe/d, a 233% increase over the fourth quarter of 2013 and a 56% sequential increase over the third quarter of 2014

Acreage and Drilling

As of December 31, 2014, the Company controlled approximately 10,000 net acres in the Williston Basin. Approximately 63% of the acreage is held by production. In 2014, the Company added 3.01 net wells to production, ending the year with a total producing well count of 7.88 net wells. Additionally, the Company had 2.8 additional net wells in development at year end. 

Management Comment

Ken DeCubellis, Black Ridge's CEO, commented, "We are proud of our execution and growth in 2014. Our disciplined process for making investment decisions has the Company on a solid foundation as we closed out 2014. Now, all of our attention has shifted to executing a plan to manage through the commodity price downturn. Measured production growth, within the context of available liquidity and prudent balance sheet risk, and our continued focus on making investment decisions that exceed our internal rate of return threshold are the pillars of our plan that will help guide the Company through the down cycle."

2015 Capital Program and Production Guidance

The Company expects 2015 capital expenditures to total approximately $16 million. The Company expects additional cash expenditures of approximately $9 million related to wells in process and accrued as of December 31, 2014. Black Ridge expects to bring 2.8 net wells online during the year, with the majority of the additions coming in the third and fourth quarters. The Company's Teton and Corral Creek Unit projects are expected to comprise approximately 75% of the net well additions. These two projects, located in core of the Williston Basin in eastern McKenzie and northern Dunn counties, respectively, are expected to meet or exceed the Company's return thresholds based on current oil prices. As the price environment dictates, the Company may look to strategically divest mature producing assets. Total Company production is expected to average approximately 1,100 boe/d in 2015.

Liquidity Position and Borrowing Base

Black Ridge ended the year with $22.6 million drawn on its $35 million senior secured revolving credit facility. Subsequent to year-end, the senior secured borrowing base was re-determined to $34 million. The next redetermination date is scheduled for October 1, 2015.

Hedging Update

In 2014, the Company realized a $511,451 gain on settled derivatives and a $7,793,421 unrealized gain on mark-to-market adjustments to its outstanding derivatives contracts. The following table summarizes the Company's open derivatives contracts as of December 31, 2014.

 

Weighted Average Price of

Open Commodity Swap Contracts





Weighted



Volumes


Average

Year


(Bbl)


Price (WTI)

2015


87,000


$

89.84

2016


84,000


$

89.73

2017


78,000


$

87.18

 

In addition to the open commodity 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 contracts as of December 31, 2014.

 



Oil


Floor/Ceiling



Term


(Barrels)


Price (WTI)


Basis

Costless Collars – Crude Oil







01/01/2015 – 12/31/2015


36,000


$75.00/$95.60


NYMEX

01/01/2016 – 06/30/2016


10,002


$80.00/$89.50


NYMEX

 

2014 Operating and Financial Results

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

 


Year Ended




December 31,




2014


2013


% Change

Net Production:








Oil (Bbl)


256,256



99,979


156

Natural Gas (Mcf)


213,141



52,973


302

Barrel of Oil Equivalent (Boe)


291,780



108,808


168

Average Daily Production (Boe/d)


799



298


168









Average Sales Prices:








Oil (per Bbl)

$

78.64


$

89.58


(12)

Effect of oil hedges on average price (per Bbl)

$

1.99


$

0.54



Oil net of hedging (per Bbl)

$

80.63


$

90.12


(11)

Natural Gas (per Mcf)

$

4.46


$

6.04


(26)

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

$

-


$

-



Natural gas net of hedging (per Mcf)

$

4.46


$

6.04


(26)









Per Boe including settled derivatives

$

74.08


$

85.75


(14)









Operating Expenses (per Boe):








Production Expenses

$

9.27


$

10.53


(12)

Production Taxes

$

7.55


$

9.34


(19)

G&A Expense

$

9.91


$

21.14


(53)

Depletion, Depreciation, Amortization and Accretion

$

32.26


$

34.36


(6)

 

Year-End 2014 Results

For the full year 2014, Company production increased to 291.8 Mboe, an average of 799 Boe/d, representing a 168% increase over 2013 production of 108.8 MBoe. Oil and gas sales were $21.1 million, compared to $9.3 million in 2013, an increase of 127%. The increase in production and revenues was due to the completion of an additional 94 gross (3.01 net) wells in 2014.

During 2014, the Company realized an average price of $78.64 per Bbl of oil compared to an average price of $89.58 per Bbl of oil in 2013. The Company's production was comprised of 88% oil and 12% natural gas and natural gas liquids in 2014 on a Boe basis.

Lease operating expenses for 2014 were $2.7 million, or $9.27 per Boe, compared to $1.1 million, or $10.53 per Boe, for 2013.

General and administrative expenses ("G&A") for 2014 were $2.9 million, or $9.91 per Boe, compared to $2.3 million, or $21.14 per Boe for 2013. Cash G&A (non-GAAP, excludes stock-based compensation expense) was $2.3 million, or $7.93 per Boe for 2014 compared to $1.7 million, or $15.22 per Boe for 2013.

The Company recorded $14.4 million of adjusted EBITDA in 2014, representing an increase of 145% from $5.9 million of adjusted EBITDA in 2013. Adjusted EBITDA is a non-GAAP financial measure. Please refer to the reconciliation in this release for additional information about this measure.

Fourth Quarter 2014 Operating and Financial Results

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

 


Three Months Ended




December 31,




2014


2013


% Change

Net Production:








Oil (Bbl)


91,686



29,394


212

Natural Gas (Mcf)


106,683



21,135


405

Barrel of Oil Equivalent (Boe)


109,467



32,916


233

Average Daily Production (Boe/d)


1,190



358


233









Average Sales Prices:








Oil (per Bbl)

$

62.35


$

84.24


(26)

Effect of oil hedges on average price (per Bbl)

$

10.48


$

2.54



Oil net of hedging (per Bbl)

$

72.83


$

86.78


(16)

Natural Gas (per Mcf)

$

2.90


$

5.94


(51)

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

$

-


$

-



Natural gas net of hedging (per Mcf)

$

2.90


$

5.94


(51)









Per Boe including settled derivatives

$

63.82


$

81.31


(22)









Operating Expenses (per Boe):








Production Expenses

$

8.52


$

10.11


(16)

Production Taxes

$

5.64


$

8.90


(37)

G&A Expense

$

7.28


$

17.76


(59)

Depletion, Depreciation, Amortization and Accretion

$

30.85


$

32.89


(6)

 

Fourth Quarter 2014 Results

During the fourth quarter of 2014, Company production totaled 109.5 Mboe, an average of 1,190 Boe/d, representing a sequential increase of 56% over third quarter 2014 production of 70.0 Mboe and a year-over-year increase of 233% over 32.9 Mboe in the fourth quarter of 2013.

Oil and gas sales, which exclude the effect of derivatives, totaled $6.0 million in the fourth quarter of 2014, compared to $2.6 million in the fourth quarter of 2013, an increase of 132%.

Average realized prices for the fourth quarter of 2014, before the effect of commodity derivatives, were $62.35 per Bbl of oil and $2.90 per Mcf of natural gas, compared to $84.24 per Bbl of oil and $5.94 per Mcf of natural gas in the fourth quarter of 2013.

Lease operating expenses for the fourth quarter of 2014 were $932 thousand, or $8.52 per Boe, compared to $333 thousand, or $10.11 per Boe for the fourth quarter of 2013, a decrease of 16% on a per Boe basis.

General and administrative expenses ("G&A") for the fourth quarter of 2014 were $797 thousand, or $7.28 per Boe, compared to $584 thousand, or $17.76 per Boe for the fourth quarter of 2013. Cash G&A (non-GAAP, excludes stock-based compensation expense) was $651 thousand, or $5.95 per Boe for the fourth quarter of 2014 compared to $442 thousand, or $13.44 per Boe for the fourth quarter of 2013.

The Company recorded $4.8 million of adjusted EBITDA in the fourth quarter of 2014, representing a 143% increase over $2.0 million of adjusted EBITDA in the fourth quarter of 2013. Adjusted EBITDA is a non-GAAP financial measure. Please refer to the reconciliation in this release for additional information about this measure.

2014 Proved Reserves

As of December 31, 2014, Black Ridge had estimated proved reserves of 5.4 MMBoe, of which 38% were classified as proved developed, and 90% was crude oil. These estimated proved reserves had a pre-tax PV10% value of $100.3 million, a 35% increase over 2013 proved reserves pre-tax PV10% value of $74.4 million. Reserve replacement for the Company in 2014 was 280%. The Company's estimated reserves were prepared by its independent reservoir engineering firm, Netherland, Sewell & Associates, Inc.

 



Reserve
Category(1)

% of
Reserves


Oil
(MBbls)


Gas
(MMcf)


2014
Mboe(2)


2013
Mboe


%
Change


2014 PV-10(3)
($000's)

Proved Developed Producing

36%


1,688


1,276


1,901


998


90%


$

58,939

Proved Developed Non-Producing

2%


111


87


126


38


332%



4,743

Proved Undeveloped

62%


2,999


1,984


3,329


3,502


(5%)



36,693

Total Proved

100%


4,798


3,347


5,356


4,538


18%


$

100,335



1)

The SEC Pricing Proved Reserves table above values crude oil and natural gas reserve quantities and related discounted future net cash flows as of December 31, 2014 assuming a constant realized price of $83.26 per barrel of crude oil and a constant realized price of $7.10 per Mcf of natural gas. The values presented in both tables above were calculated by Netherland, Sewell & Associates, Inc.









(2)

BOE are computed based on a conversion ratio of one BOE for each barrel of crude oil and one BOE for every 6,000 cubic feet (i.e., 6 Mcf) of natural gas.









(3)

Pre-tax PV10% may be considered a non-GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable standardized financial measure. Pre-tax PV10% is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting future income taxes. We believe Pre-tax PV10% is a useful measure for investors for evaluating the relative monetary significance of our crude oil and natural gas properties. We further believe investors may utilize our Pre-tax PV10% as a basis for comparison of the relative size and value of our reserves to other companies because many factors that are unique to each individual company impact the amount of future income taxes to be paid. Our management uses this measure when assessing the potential return on investment related to our crude oil and natural gas properties and acquisitions. However, Pre-tax PV10% is not a substitute for the standardized measure of discounted future net cash flows. Our Pre-tax PV10% and the standardized measure of discounted future net cash flows do not purport to present the fair value of our crude oil and natural gas reserves.


 

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 December 31, 2014.

 

Well

Operator

Location

WI(1)

Matilda Bay 1-15H

Slawson

Williams, ND

0.100

McCracken 2758 21-10 5B

Oasis

Roosevelt, MT

0.071

McCracken 2758 44-9 4B

Oasis

Roosevelt, MT

0.071

McCracken 2758 34-9 3B

Oasis

Roosevelt, MT

0.071

McCracken 2758 41-10 6B

Oasis

Roosevelt, MT

0.071

Ironbank 5-14-13TFH

Slawson

Williams, ND

0.055

Revolver 7-35TFH

Slawson

Mountrail, ND

0.016

CCU Powell 41-29MBH

Burlington Resources

Dunn, ND

0.008

CCU Olympian 11-2TFH

Burlington Resources

Dunn, ND

0.008

Jersey 23-6H1

Continental

Mountrail, ND

0.008

Jersey 24-6H3

Continental

Mountrail, ND

0.008

Jersey 25-6H

Continental

Mountrail, ND

0.008

Jersey 26-6H2

Continental

Mountrail, ND

0.008

Jersey 27-6H1

Continental

Mountrail, ND

0.008

Jersey 28-6H3

Continental

Mountrail, ND

0.008

Jersey 29-6XH

Continental

Mountrail, ND

0.008

(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 December 31, 2014.

 

Well

Operator

Location

WI(1)

Bootleg 6-14-15TFH

Slawson

Williams, ND

0.113

Bootleg 7-14-15TFH

Slawson

Williams, ND

0.113

Bootleg 8-14-15TF2H

Slawson

Williams, ND

0.113

Rainbow 10-19-18HBK

Samson Oil and Gas

Williams, ND

0.100

Teton 5-1-3TFSH

Burlington Resources

McKenzie, ND

0.088

Kings Canyon 6-8-34UTFH

Burlington Resources

McKenzie, ND

0.088

Kings Canyon 4-8-34UTFH

Burlington Resources

McKenzie, ND

0.088

Kings Canyon 4-8-34MBH

Burlington Resources

McKenzie, ND

0.088

Teton 2-8-10MBH

Burlington Resources

McKenzie, ND

0.088

Teton 3-8-10MBH

Burlington Resources

McKenzie, ND

0.088

Teton 8-8-10TFSH

Burlington Resources

McKenzie, ND

0.088

Teton 7-1-3TFSH

Burlington Resources

McKenzie, ND

0.088

Kings Canyon 7-8-34MBH

Burlington Resources

McKenzie, ND

0.088

Kings Canyon 5-8-34UTF

Burlington Resources

McKenzie, ND

0.088

Teton 5-8-10MBH

Burlington Resources

McKenzie, ND

0.088

Teton 6-8-10TFSH

Burlington Resources

McKenzie, ND

0.088

Teton 7-8-10MBH

Burlington Resources

McKenzie, ND

0.088

Kings Canyon 2-8-34UTFH

Burlington Resources

McKenzie, ND

0.088

Kings Canyon 3-1-27MTFH

Burlington Resources

McKenzie, ND

0.088

Kings Canyon 6-1-27MBH

Burlington Resources

McKenzie, ND

0.088

Kings Canyon 6-1-27MTFH

Burlington Resources

McKenzie, ND

0.088

Kings Canyon 4-1-27MTFH

Burlington Resources

McKenzie, ND

0.088

Teton 6-8-10MBH

Burlington Resources

McKenzie, ND

0.088

Billabong 2-13-14HBK

Slawson

Williams, ND

0.075

Remingteton 8-8-10MBH

Burlington Resources

McKenzie, ND

0.062

Ironbank 4-14-13TFH

Slawson

Williams, ND

0.055

Ironbank 7-14-13TFH

Slawson

Williams, ND

0.054

Ironbank 6-14-13TFH

Slawson

Williams, ND

0.054

DeKing 1-8-34MBH-ULW

Burlington Resources

McKenzie, ND

0.021

Gobbler 6-35-26TFH

Slawson

Mountrail, ND

0.008

Duletski Federal 14-12PH

Whiting

Billings, ND

0.008

Aaberg 8-5N-1H

Mountain Divide

Divide, ND

0.008

CCU Powell 41-29TFH

Burlington Resources

Dunn, ND

0.008

CCU Pullman 2-8-7MBH

Burlington Resources

Dunn, ND

0.008

CCU Pullman 5-8-7TFH

Burlington Resources

Dunn, ND

0.008

CCU Pullman 5-8-7MBH

Burlington Resources

Dunn, ND

0.008

CCU Pullman 6-8-7TFH

Burlington Resources

Dunn, ND

0.008

CCU Pullman 8-8-7TFH

Burlington Resources

Dunn, ND

0.008

CCU Pullman 7-8-7MBH

Burlington Resources

Dunn, ND

0.008

CCU Pullman 7-8-7TFH

Burlington Resources

Dunn, ND

0.008

CCU North Coast 31-25MBH

Burlington Resources

Dunn, ND

0.008

CCU North Coast 31-25TFH

Burlington Resources

Dunn, ND

0.008

CCU Pullman 6-8-7MBH

Burlington Resources

Dunn, ND

0.008

CCU Pullman 1-8-7TFH

Burlington Resources

Dunn, ND

0.008

CCU Pullman 3-8-7TFH

Burlington Resources

Dunn, ND

0.008

CCU Pullman 3-8-7MBH

Burlington Resources

Dunn, ND

0.008

CCU North Coast 4-8-23MBH

Burlington Resources

Dunn, ND

0.008

CCU North Coast 41-25MBH

Burlington Resources

Dunn, ND

0.008

CCU North Coast 4-8-23TFH

Burlington Resources

Dunn, ND

0.008

CCU Golden Creek 44-23TFH

Burlington Resources

Dunn, ND

0.008

CCU Golden Creek 44-23MBH

Burlington Resources

Dunn, ND

0.008

CCU North Coast 41-25TFH

Burlington Resources

Dunn, ND

0.008

CCU Main Streeter 24-24TFH

Burlington Resources

Dunn, ND

0.008

CCU Main Streeter 14-24MBH

Burlington Resources

Dunn, ND

0.008

CCU Dakotan 2-7-17MBH

Burlington Resources

Dunn, ND

0.008

CCU Dakotan 1-7-17TFH

Burlington Resources

Dunn, ND

0.008

CCU Dakotan 1-7-17MBH

Burlington Resources

Dunn, ND

0.008

CCU Dakotan 2-7-17TFH

Burlington Resources

Dunn, ND

0.008

CCU Dakotan 5-8-17TFH

Burlington Resources

Dunn, ND

0.008

CCU Dakotan 6-8-17MBH

Burlington Resources

Dunn, ND

0.008

CCU Dakotan 7-8-17TFH

Burlington Resources

Dunn, ND

0.008

CCU Dakotan 7-8-17MBH

Burlington Resources

Dunn, ND

0.008

CCU Dakotan 5-8-17MBH

Burlington Resources

Dunn, ND

0.008

CCU Dakotan 4-8-17TFH

Burlington Resources

Dunn, ND

0.008

Jersey 1-6H

Continental

Mountrail, ND

0.008

Jersey 3-6H1

Continental

Mountrail, ND

0.008

Jersey 2-6H2

Continental

Mountrail, ND

0.008

Jersey 7-6H

Continental

Mountrail, ND

0.008

Jersey 6-6H1

Continental

Mountrail, ND

0.008

Jersey 4-6H3

Continental

Mountrail, ND

0.008

Jersey 8-6H1

Continental

Mountrail, ND

0.008

Jersey 5-6H

Continental

Mountrail, ND

0.008

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

Kodiak

Williams, ND

0.006

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

Kodiak

Williams, ND

0.006

Oakdale 2-13H1

Continental

Dunn, ND

0.006

Ryden 3-24H

Continental

Dunn, ND

0.006

Ryden 2-24AH1

Continental

Dunn, ND

0.006

Oakdale 5-13H

Continental

Dunn, ND

0.006

Oakdale 3-13H

Continental

Dunn, ND

0.006

Oakdale 4-13H1

Continental

Dunn, ND

0.006

Ryden 4-24H1

Continental

Dunn, ND

0.006

(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 Income (Loss) and Adjusted EBITDA

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 settlement income, net of settlement expenses, and 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, and (v) 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, are included below:


 

Reconciliation of Net Income (Loss) to Adjusted Net Income (Loss)





Three Months Ended December 31,


Years Ended December 31,


2014


2013


2014


2013

Net income (loss)

$

4,086,084


$

(195,508)


$

4,351,880


$

(402,659)

Subtract:












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


(4,245,782)



105,451



(4,909,421)



134,676

Settlement income, net of tax (b)


-



(227,505)



-



(227,505)

Adjusted net income (loss)

$

(159,698)


$

(317,562)


$

(557,541)


$

(495,488)













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


48,815,177



47,979,990



49,179,725



47,979,990













Net income (loss) per common share - basic

$

0.09


$

0.00


$

0.09


$

(0.01)

Subtract:












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


(0.09)



0.00



(0.10)



0.00

Settlement income per common share, net of tax


-



(0.00)



-



(0.00)

Adjusted net income (loss) per common share - basic

$

0.00


$

(0.00)


$

(0.01)


$

(0.01)













Net income (loss) per common share - fully diluted

$

0.08


$

0.00


$

0.09


$

(0.01)

Subtract:












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


(0.09)



0.00



(0.10)



0.00

Settlement income per common share, net of tax


-



(0.00)



-



0.00

Adjusted net income (loss) per common share - fully diluted

$

(0.01)


$

(0.00)


$

(0.01)


$

(0.01)


(a) Adjusted to reflect tax (expense) benefit, computed based on our effective tax rates of approximately 37% in 2014 and 2013, of ($2,494,000) and $62,000, respectively, for the three months ended December 31, 2014 and 2013 and ($2,884,000) and $79,000, respectively, for the years ended December 31, 2014 and 2013.

(b) Adjusted to reflect tax expense, computed based on our effective tax rate of approximately 37% in 2013, of $134,000, for the three months and year ended December 31, 2013.

 

Reconciliation of Net Income (Loss) to Adjusted EBITDA



Three Months Ended December 31,


Years Ended December 31,


2014


2013


2014


2013

Net income (loss)

$

4,086,084


$

(195,508)


$

4,351,880


$

(402,659)

Add back:












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


1,309,414



706,231



4,656,069



2,072,129

Income tax provision


2,448,346



(83,442)



2,559,195



(698,851)

Depreciation, depletion, and amortization


3,370,583



1,078,394



9,389,090



3,729,157

Accretion of abandonment liability


6,875



4,245



22,361



9,019

Share-based compensation


305,150



292,662



1,207,114



951,639

Losses (gains) on the mark-to-market of derivatives


(6,740,782)



167,451



(7,793,421)



213,676













Adjusted EBITDA

$

4,785,670


$

1,970,033


$

14,392,288


$

5,874,110


Our adjusted EBITDA includes settlement income, net of settlement expenses, of $361,505 for the three months and year ended December 31, 2013.

 

BLACK RIDGE OIL & GAS, INC.

BALANCE SHEETS










December 31,


December 31,


2014


2013

ASSETS








Current assets:




Cash and cash equivalents

$        94,682


$   1,150,347

Derivative instruments

3,571,803


-

Accounts receivable

5,740,171


1,905,467

Advances to operators

-


1,214,662

Prepaid expenses

41,387


26,142

Total current assets

9,448,043


4,296,618





Property and equipment:




Oil and natural gas properties, full cost method of accounting




Proved properties

112,418,105


79,361,432

Unproved properties

591,121


2,798,795

Other property and equipment

139,004


115,482

Total property and equipment

113,148,230


82,275,709

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

(18,902,524)


(9,513,434)

Total property and equipment, net

94,245,706


72,762,275





Derivative instruments

4,007,942


-

Debt issuance costs, net

701,019


772,883





Total assets

$108,402,710


$ 77,831,776









LIABILITIES AND STOCKHOLDERS' EQUITY








Current liabilities:




Accounts payable

$ 10,291,262


$   8,453,709

Accrued expenses

57,435


4,813

Derivative instruments

-


139,065

Total current liabilities

10,348,697


8,597,587





Derivative instruments

-


74,611

Asset retirement obligations

286,804


160,665

Revolving credit facility and long term debt,
net of discounts of $2,072,483 and $2,645,582, respectively

51,834,603


30,556,301

Deferred tax liability

6,593,040


4,033,845





Total liabilities

69,063,144


43,423,009





Commitments and contingencies (See note 14)

-


-





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

33,651,714


33,072,795

Retained earnings

5,639,872


1,287,992

Total stockholders' equity

39,339,566


34,408,767





Total liabilities and stockholders' equity

$108,402,710


$ 77,831,776

 

BLACK RIDGE OIL & GAS, INC.

STATEMENTS OF OPERATIONS


















For the Three Months


For the Years


Ended December 31,


Ended December 31,


2014


2013


2014


2013









Oil and gas sales

$      6,026,080


$   2,601,716


$21,102,823


$ 9,276,656

Gain on settled derivatives

960,586


74,666


511,451


53,482

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

6,740,782


(167,451)


7,793,421


(213,676)

Total revenues

$    13,727,448


$   2,508,931


$29,407,695


$ 9,116,462









Operating expenses:








Production expenses

932,305


332,663


2,705,763


1,145,686

Production taxes

617,746


292,921


2,203,501


1,015,907

General and administrative

796,570


584,470


2,891,641


2,299,757

Depletion of oil and gas properties

3,365,772


1,071,847


9,359,952


3,705,156

Accretion of discount on asset retirement obligations

6,875


4,245


22,361


9,019

Depreciation and amortization

4,811


6,547


29,138


24,001

Total operating expenses

5,724,079


2,292,693


17,212,356


8,199,526









Net operating income

8,003,369


216,238


12,195,339


916,936









Other income (expense):








Interest income

-


67


972


408

Interest (expense)

(1,468,939)


(856,760)


(5,285,236)


(2,380,359)

Settlement income

-


380,982


-


380,982

Settlement expense

-


(19,477)


-


(19,477)

Total other income (expense)

(1,468,939)


(495,188)


(5,284,264)


(2,018,446)









Income (loss) before provision for income taxes

6,534,430


(278,950)


6,911,075


(1,101,510)









Provision for income taxes

(2,448,346)


83,442


(2,559,195)


698,851









Net income (loss)

$      4,086,084


$    (195,508)


$ 4,351,880


$  (402,659)

















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

48,815,177


47,979,990


49,179,725


47,979,990









Net income (loss) per common share - basic

$               0.09


$          (0.00)


$          0.09


$        (0.01)

Net income (loss) per common share - fully diluted

$               0.08


$          (0.00)


$          0.09


$        (0.01)

 

BLACK RIDGE OIL & GAS, INC.

STATEMENTS OF CASH FLOWS










For the Years


Ended December 31,


2014


2013

CASH FLOWS FROM OPERATING ACTIVITIES




Net income (loss)

$  4,351,880


$  (402,659)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:




Depletion of oil and gas properties

9,359,952


3,705,156

Depreciation and amortization

29,138


24,001

Amortization of debt issuance costs

326,258


749,920

Accretion of discount on asset retirement obligations

22,361


9,019

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

(7,793,421)


213,676

Accrued payment in kind interest applied to long term debt

1,105,203


201,883

Amortization of original issue discount on debt

144,904


28,362

Amortization of debt discounts, warrants

628,195


199,632

Common stock warrants granted as financing costs

-


108,190

Common stock options issued to employees and directors

578,919


643,817

Deferred income taxes

2,559,195


(698,851)

Decrease (increase) in current assets:




Accounts receivable

(2,834,704)


(1,049,234)

Settlement receivable

-


2,500,000

Prepaid expenses

(15,245)


21,013

Increase (decrease) in current liabilities:




Accounts payable

426,558


164,527

Settlement payable

-


(160,000)

Settlement payable, related parties

-


(116,234)

Accrued expenses

52,622


(56,853)

Net cash provided by operating activities

8,941,815


6,085,365





CASH FLOWS FROM INVESTING ACTIVITIES




Proceeds from sale or swap of oil and gas properties

1,441,929


608,387

Purchases of oil and gas properties and development capital expenditures

(24,739,407)


(32,025,724)

Advances to operators

(5,822,086)


(882,604)

Purchases of other property and equipment

(23,522)


(38,472)

Net cash used in investing activities

(29,143,086)


(32,338,413)





CASH FLOWS FROM FINANCING ACTIVITIES




Advances from revolving credit facilities and long term debt

29,800,000


41,150,000

Repayments on revolving credit facilities

(10,400,000)


(14,298,844)

Debt issuance costs

(254,394)


(865,101)

Net cash provided by financing activities

19,145,606


25,986,055





NET CHANGE IN CASH

(1,055,665)


(266,993)

CASH AT BEGINNING OF PERIOD

1,150,347


1,417,340

CASH AT END OF PERIOD

$       94,682


$  1,150,347









SUPPLEMENTAL INFORMATION:




Interest paid

$  3,401,028


$  1,104,688

Income taxes paid

$                 -


$                 -





NON-CASH INVESTING AND FINANCING ACTIVITIES:




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

$  1,410,995


$  5,335,656

Advances to operators received in swap for oil and gas properties

$                 -


$(1,200,000)

Advances to operators applied to purchase of oil and gas properties

$  6,036,748


$  2,218,237

Advances to operators reclassified to accounts receivable

$  1,000,000


$                 -

Capitalized asset retirement costs, net of revision in estimate

$     103,778


$       84,501

Fair value of detachable warrants granted in consideration of debt financing

$                 -


$  2,473,576

 

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-2014-fourth-quarter-and-full-year-results-300057893.html

SOURCE Black Ridge Oil & Gas, Inc.