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Company News

Black Ridge Oil & Gas Announces 2013 Fourth Quarter and Full Year Results

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Pro Forma Q4 2013 Production of 482 Boe/d

PV10% of Proved Reserves of $74.4 million, Up 166% over $27.9 million in 2012

Annual Adjusted EBITDA from Oil and Gas Operations Up 126% to $5.5 Million

Annual Revenue Up 51% to $9.1 Million

MINNETONKA, Minn., March 27, 2014 /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, 2013.

Full Year 2013 Company Highlights

  • Increased annual production 47% from 2012 to 108.8 thousand barrels of oil equivalent ("MBoe"), an average of approximately 298 barrels of oil equivalent per day ("Boe/d")
  • Increased annual revenue 51% to $9.1 million from $6.0 million in 2012
  • Increased total proved reserves, as determined by Netherland, Sewell & Associates, Inc., to 4.5 million Boe, an increase of 90% from 2012
  • Increased pre-tax PV10% of the total proved reserves as of December 31, 2013 to $74.4 million, an increase of 166% from 2012
  • Exited 2013 with production from 153 gross (4.87 net) wells, up from 66 gross (2.30 net) at the end of 2012, an increase of 112% on a net well basis
  • Recorded $5.5 million of adjusted EBITDA from oil and gas operations (excluding net settlement income), an increase of 126% from $2.4 million in 2012

Fourth Quarter 2013 Company Highlights

  • Increased quarterly production to 32.9 MBoe, an average of 358 MBoe/d, representing a 61% increase over the fourth quarter of 2012 and a 16% increase over the third quarter of 2013
  • Pro forma fourth quarter production including the Corral Creek acquisition, which closed on December 13, 2013, averaged 482 Boe/d
  • Increased revenue to $2.5 million, a 48% increase from the fourth quarter of 2012
  • Completed or acquired 61 gross (1.65 net) wells during the quarter

Corral Creek Acquisition
As previously disclosed, the Company closed on the Corral Creek acquisition on December 13, 2013. The year-end financial information provided herein by the Company reflects the impact of the acquired assets from the closing date to December 31, 2013 (19 days).

Management Comment
Ken DeCubellis, Black Ridge's CEO, commented, "The Company had an outstanding year in 2013. We successfully executed on our key initiatives of acquiring high quality, core Bakken acreage with near-term development and securing financing to execute our aggressive growth plan. Looking ahead to 2014, we are encouraged by early results from both our Stockyard Creek and Corral Creek prospects and expect these assets to drive robust production growth in 2014 and beyond."

Year-End 2013 Results
For the full year 2013, Company production increased to 108.8 Mboe, an average of 298 Boe/d, representing a 47% increase over 2012 production of 73.9 MBoe.  Revenues were $9.1 million, compared to $6.0 million in 2012, an increase of 51%. The increase in production and revenues was due to the completion or purchase of an additional 87 gross (2.57 net) wells in 2013. 

During 2013, the Company realized an average price of $89.58 per Bbl of oil compared to an average price of $83.27 per Bbl of oil in 2012. The Company's production was comprised of 92% oil and 8% natural gas and natural gas liquids in 2013 on a Boe basis.

Lease operating expenses for 2013 were $1.1 million, or $10.53 per Boe, compared to $650 thousand, or $8.79 per Boe, for 2012.

General and administrative expenses ("G&A") for 2013 were $2.3 million, or $21.14 per Boe, compared to $3.5 million, or $47.75 per Boe for 2012. Cash G&A (non-GAAP, excludes stock-based compensation expense) was $1.7 million, or $15.22 per Boe for 2013 compared to $2.2 million, or $30.33 per Boe for 2012. Included in the 2012 G&A expenses were one-time legal costs of $371 thousand associated with litigation settlement activity.

The Company recorded $5.5 million of adjusted EBITDA from oil and gas operations (excluding net settlement income) in 2013, representing an increase of 126% from $2.4 million in 2012.  Adjusted EBITDA is a non-GAAP financial measure. Please refer to the reconciliation in this release for additional information about this measure.

Fourth Quarter 2013 Results
During the fourth quarter of 2013, Company production totaled 32.9 Mboe, an average of 358 Boe/d, representing a sequential increase of 16% over third quarter 2013 production of 28.4 Mboe and a year-over-year increase of 61% over 20.4 Mboe in the fourth quarter of 2012.  Pro forma for the Corral Creek acquisition that closed December 13, 2013, fourth quarter production averaged 482 Boe/d. 

Revenues for the fourth quarter of 2013 were $2.5 million, compared to $1.7 million in the fourth quarter of 2012, an increase of 48%.

Average realized prices for the fourth quarter of 2013, before the effect of commodity derivatives, were $84.24 per Bbl of oil and $5.94 per Mcf of natural gas, compared to $85.15 per Bbl of oil and $5.90 per Mcf of natural gas in the fourth quarter of 2012.

Lease operating expenses for the fourth quarter of 2013 were $333 thousand, or $10.11 per Boe, compared to $222 thousand, or $10.85 per Boe, for the fourth quarter of 2012.

General and administrative expenses ("G&A") for the fourth quarter of 2013 were $584 thousand, or $17.76 per Boe, compared to $575 thousand, or $28.13 per Boe for the fourth quarter of 2012. Cash G&A (non-GAAP, excludes stock-based compensation expense) was $442 thousand, or $13.44 per Boe for the fourth quarter of 2013 compared to $424 thousand, or $20.75 per Boe for the fourth quarter of 2012.

The Company recorded $1.6 million of adjusted EBITDA from oil and gas operations (excluding net settlement income) in the fourth quarter of 2013, representing an 83% increase over $878 thousand in the fourth quarter of 2012. Adjusted EBITDA is a non-GAAP financial measure. Please refer to the reconciliation in this release for additional information about this measure.

2013 Proved Reserves
As of December 31, 2013, Black Ridge had estimated proved reserves of 4.5 MMBoe, of which 23% were classified as proved developed, and 90% was crude oil. These estimated proved reserves had a pre-tax PV10% value of $74.4 million, a 166% increase over 2012 proved reserves pre-tax PV10% value of $27.9 million. Reserve replacement for the Company in 2013 was 1,980%. The Company's estimated reserves were prepared by its independent reservoir engineering firm, Netherland, Sewell & Associates, Inc.


     Reserve Category

% of Reserves


Oil (MBbls)


Gas (MMcf)


2013 Mboe


2012 Mboe


% Change


2013 PV-10 ($000's)

Proved Developed Producing

22%


895


615


998


509


96%


$

32,379

Proved Developed Non-Producing

1%


32


38


38


-


n/a



1,609

Proved Undeveloped

77%


3,147


2,126


3,502


1,875


87%



40,389

Total Proved

100%


4,074


2,779


4,538


2,384


90%


$

74,377

(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, 2013 assuming a constant realized price of $88.93 per barrel of crude oil and a constant realized price of $8.25 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.

Liquidity Position
In August 2013, Black Ridge closed on a $50 million senior secured revolving credit facility and a $75 million second lien term loan facility. The initial capital available to the Company was $32 million, nearly double the availability from the Company's previous financing. In connection with the December closing of the Corral Creek acquisition, the capital available to the Company was increased to $43 million. As of December 31, 2013, the Company had drawn $33 million from these facilities.

Black Ridge expects to continue to use these two new facilities as well as cash flow from operations to accelerate the growth of the Company's footprint in the Bakken and Three Forks trends through potential working interest and/or leasehold purchases and development of wells on the Company's existing leases.

Operational Update
As of December 31, 2013, the Company owned interests in 153 gross (4.87 net) producing wells. Additionally, the Company owned interest in 55 gross (1.40 net) wells that were preparing to drill, drilling, awaiting completion, or completing ("drilling") as of December 31, 2013. A full list of producing and "drilling" wells is available at www.blackridgeoil.com.

As of December 31, 2013, the Company controlled approximately 10,000 net acres prospective for the Bakken and Three Forks formations. Additionally, the Company controlled approximately 4,200 net acres in southeastern Dunn County that do not appear to hold commercially economic reserve quantities and their respective leases will not be renewed or extended upon expiration in the first half of 2014.

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, 2013.


Well

Operator

Location

WI(1)

Gorhman 14-31TFH

Burlington Resources

Dunn, ND

0.193

Gorhman 24-31MBH

Burlington Resources

Dunn, ND

0.193

Rogers-Federal #1-15

XTO Energy

Williams, ND

0.183

Peter 4-2H

SM Energy

Divide, ND

0.125

Teton 21-3H

Burlington Resources

McKenzie, ND

0.125

Charlotte #1-12-1H

Mountain Divide

Divide, ND

0.083

Lincoln USA 16-1H

Marathon

Dunn, ND

0.064

Raymond 1-21AH

Continental

Williams, ND

0.043

Metz 6094 13-1H

Oasis

Burke, ND

0.040

Halliday 1-11-2H 1

Hunt

Dunn, ND

0.031

Halliday 2-11-2H

Hunt

Dunn, ND

0.031

Halliday 3-11-2H

Hunt

Dunn, ND

0.031

Hansen Ranch 14-10H

Marathon

Dunn, ND

0.031

Hansen Ranch 34-10TFH

Marathon

Dunn, ND

0.031

Hansen Ranch USA 44-10H

Marathon

Dunn, ND

0.031

Hansen Ranch USA 44-10TFH

Marathon

Dunn, ND

0.031

Margaret 5-8 #4H

Statoil

McKenzie, ND

0.020

Margaret 5-8 #6H

Statoil

McKenzie, ND

0.020

Little Muddy 11H

Triangle

Williams, ND

0.009

Little Muddy 13H

Triangle

Williams, ND

0.009

CCU Audubon 41-27H

Burlington Resources

Dunn, ND

0.008

CCU Bison Point 14-34H

Burlington Resources

Dunn, ND

0.008

CCU Bison Point 44-34MBH

Burlington Resources

Dunn, ND

0.008

CCU Bison Point 44-34TFH

Burlington Resources

Dunn, ND

0.008

CCU Boxcar 21-15H

Burlington Resources

Dunn, ND

0.008

CCU Burner 21-26MBH

Burlington Resources

Dunn, ND

0.008

CCU Burner 21-26TFH

Burlington Resources

Dunn, ND

0.008

CCU Burner 41-26H

Burlington Resources

Dunn, ND

0.008

CCU Carol 44-31H

Burlington Resources

Dunn, ND

0.008

CCU Columbian 24-36H

Burlington Resources

Dunn, ND

0.008

CCU Corral Creek 41-28TFH

Burlington Resources

Dunn, ND

0.008

CCU Corral Creek 41-28MBH

Burlington Resources

Dunn, ND

0.008

CCU Corral Creel 34-33H

Burlington Resources

Dunn, ND

0.008

CCU Four Aces 11-16H

Burlington Resources

Dunn, ND

0.008

CCU Four Aces 44-21MBH

Burlington Resources

Dunn, ND

0.008

CCU Four Aces 44-21TFH

Burlington Resources

Dunn, ND

0.008

CCU Golden Creek 24-23MBH

Burlington Resources

Dunn, ND

0.008

CCU Golden Creek 34-23MBH

Burlington Resources

Dunn, ND

0.008

CCU Meriwether 14-19MBH

Burlington Resources

Dunn, ND

0.008

CCU Meriwether 14-19TFH

Burlington Resources

Dunn, ND

0.008

CCU Meriwether 24-19MBH

Burlington Resources

Dunn, ND

0.008

CCU Meriwether 24-19TFH

Burlington Resources

Dunn, ND

0.008

CCU Meriwether 34-19TFH

Burlington Resources

Dunn, ND

0.008

CCU Meriwether 44-19MBH

Burlington Resources

Dunn, ND

0.008

CCU Meriwether 44-19TFH

Burlington Resources

Dunn, ND

0.008

CCU North Coast 11-25H

Burlington Resources

Dunn, ND

0.008

CCU Powell 11-29MBH

Burlington Resources

Dunn, ND

0.008

CCU Powell 11-29TFH

Burlington Resources

Dunn, ND

0.008

CCU Powell 14-32H

Burlington Resources

Dunn, ND

0.008

CCU Powell 21-29MBH

Burlington Resources

Dunn, ND

0.008

CCU Powell 21-29TFH

Burlington Resources

Dunn, ND

0.008

CCU Prairie Rose 11-30TFH

Burlington Resources

Dunn, ND

0.008

CCU Prairie Rose 21-30MBH

Burlington Resources

Dunn, ND

0.008

CCU Prairie Rose 24-31H

Burlington Resources

Dunn, ND

0.008

CCU Prairie Rose 31-30MBH

Burlington Resources

Dunn, ND

0.008

CCU Prairie Rose 31-30TFH

Burlington Resources

Dunn, ND

0.008

CCU Prairie Rose 41-30MBH

Burlington Resources

Dunn, ND

0.008

CCU William 14-20H

Burlington Resources

Dunn, ND

0.008

CCU William 24-20MBH

Burlington Resources

Dunn, ND

0.008

CCU William 24-20TFH

Burlington Resources

Dunn, ND

0.008

CCU William 34-20TFH

Burlington Resources

Dunn, 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, 2013.

 


Well

Operator

Location

WI(1)

Coopers 2-15-14HBK

Slawson Exploration

Williams, ND

0.084

Little Creature 1-15-14H

Slawson Exploration

Williams, ND

0.084

Tooheys 4-15-14HBK

Slawson Exploration

Williams, ND

0.084

E Rennerfeldt 1-13H

Slawson Exploration

Williams, ND

0.081

E Rennerfeldt 2-13H

Slawson Exploration

Williams, ND

0.081

Inga Federal 41X-29C

XTO Energy

Dunn, ND

0.079

Inga Federal 41X-29D

XTO Energy

Dunn, ND

0.079

Inga Federal 41X-29H

XTO Energy

Dunn, ND

0.079

Pasternak Trust 157-100-19C-18-2H

Halcon Resources

Williams, ND

0.078

Pasternak Trust 157-100-19C-18-3H

Halcon Resources

Williams, ND

0.078

Billabong 2-13-14HBK

Samson Oil and Gas

Williams, ND

0.075

Blackdog 3-13-14H

Slawson Exploration

Williams, ND

0.075

Duckstein 1-13-14HTF

Slawson Exploration

Williams, ND

0.075

Orlynne 2-3H

SM Energy

Divide, ND

0.055

Margaret 5-8 #3TFH-R

Statoil

McKenzie, ND

0.020

Margaret 5-8 #5TFH

Statoil

McKenzie, ND

0.020

Moline 157-100-20D-17-2H

Halcon Resources

Williams, ND

0.016

Moline 157-100-20D-17-3H

Halcon Resources

Williams, ND

0.016

Amy 2-5H1

Continental

Stark, ND

0.015

Miller 157-101-12D-1-2H

Halcon Resources

Williams, ND

0.011

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

Halcon Resources

Williams, ND

0.011

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

Halcon Resources

Williams, ND

0.011

CCU Burner 41-26MBH

Burlington Resources

Dunn, ND

0.008

CCU Burner 41-26TFH

Burlington Resources

Dunn, ND

0.008

CCU Columbian 14-36TFH

Burlington Resources

Dunn, ND

0.008

CCU Columbian 24-36TFH

Burlington Resources

Dunn, ND

0.008

CCU Columbian 33-1MBH

Burlington Resources

Dunn, ND

0.008

CCU Columbian 33-1TFH

Burlington Resources

Dunn, ND

0.008

CCU Columbian 43-1MBH

Burlington Resources

Dunn, ND

0.008

CCU Columbian 43-1TFH

Burlington Resources

Dunn, ND

0.008

CCU Corral Creek 11-28TFH

Burlington Resources

Dunn, ND

0.008

CCU Four Aces 14-21TFH

Burlington Resources

Dunn, ND

0.008

CCU Mainstreeter 14-24TFH

Burlington Resources

Dunn, ND

0.008

CCU North Coast 11-25TFH

Burlington Resources

Dunn, ND

0.008

CCU Powell 31-29MBH

Burlington Resources

Dunn, ND

0.008

CCU Powell 41-29MBH

Burlington Resources

Dunn, ND

0.008

CCU Powell 41-29TFH

Burlington Resources

Dunn, ND

0.008

CCU William 14-20MBH

Burlington Resources

Dunn, ND

0.008

CCU William 14-20TFH

Burlington Resources

Dunn, ND

0.008

CCU William 34-20MBH

Burlington Resources

Dunn, ND

0.008

CCU William 44-20MBH

Burlington Resources

Dunn, ND

0.008

CCU William 44-20TFH

Burlington Resources

Dunn, ND

0.008

Kelter 7-12H3

Oasis

Williams, ND

0.004

Kelter 7-1H2

Oasis

Williams, ND

0.004

Kelter 7-1HTF3

Oasis

Williams, ND

0.004

Kelter 7-6HTF

Oasis

Williams, ND

0.004

Kelter 7-6HTF2

Oasis

Williams, ND

0.004

Archer 14-25TFH

Burlington Resources

McKenzie, ND

0.002

Archer 24-25MBH

Burlington Resources

McKenzie, ND

0.002

Archer 24-25TFH

Burlington Resources

McKenzie, ND

0.002

Archer 34-25TFH

Burlington Resources

McKenzie, ND

0.002

Archer 44-25MBH

Burlington Resources

McKenzie, ND

0.002

Archer 44-25TFH

Burlington Resources

McKenzie, ND

0.002

P Scanlan 153-98-16-9-5-12H

Kodiak

Williams, ND

0.001

P Scanlan 153-98-16-9-5-5H

Kodiak

Williams, ND

0.001



(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.


 

Hedging Update
The following table reflects the weighted average price of open commodity swap derivative contracts as of December 31, 2013, by year with associated volumes.

 

Weighted Average Price of

Open Commodity Swap Contracts





Weighted



Volumes


Average

Year


(Bbl)


Price (WTI)

2014


84,000


$

93.95

2015


24,000


$

88.28

In addition to the open commodity swap contracts, we have 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, 2013.

 



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

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,



2013


2012


2013


2012


Net income (loss)

$

(195,508)


$

2,934,202


$

(402,659)


$

4,911,410


Subtract:













Settlement income, net of tax (a)


(227,505)



(3,078,252)



(227,505)



(6,355,895)


Adjusted net income (loss)

$

(423,013)


$

(144,050)


$

(630,164)


$

(1,444,485)















Weighted average common shares outstanding - basic


47,979,990



47,979,990



47,979,990



47,789,225


Weighted average common shares outstanding - fully diluted


47,979,990



48,220,062



47,979,990



48,061,239















Net income (loss) per common share - basic

$

(0.00)


$

0.06


$

(0.01)


$

0.10


Subtract:













Settlement income per common share, net of tax


(0.00)



(0.06)



(0.00)



(0.13)


Adjusted net income (loss) per common share - basic

$

(0.01)


$

(0.00)


$

(0.01)


$

(0.03)















Net income (loss) per common share - fully diluted

$

(0.00)


$

0.06


$

(0.01)


$

0.10


Subtract:













Settlement income per common share, net of tax


(0.00)



(0.06)



(0.00)



(0.13)


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

$

(0.01)


$

(0.00)


$

(0.01)


$

(0.03)



(a) Adjusted to reflect tax expense, computed based on our effective tax rates of approximately 37% in 2013 and 43% in 2012, of $134,000 and $2,323,000, respectively, for the three months ended December 31, 2013 and 2012 and $134,000 and $4,790,000, respectively, for the years ended December 31, 2013 and 2012.


 

Reconciliation of Net Income (Loss) to Adjusted EBITDA

























Three Months Ended December 31,


Years Ended December 31,



2013


2012


2013


2012


Net income (loss)

$

(195,508)


$

2,934,202


$

(402,659)


$

4,911,410


Add back:













Interest expense, net, excluding amortization













of warrant based financing costs


706,231



377,472



2,072,129



873,754


Income tax provision


(83,442)



2,089,971



(698,851)



3,720,601


Depreciation, depletion, and amortization


1,078,394



715,540



3,729,157



2,467,688


Accretion of abandonment liability


4,245



1,213



9,019



4,557


Common stock issued for terminated oil and gas













acquisition


-



-



-



438,539


Share-based compensation


292,662



161,023



951,639



1,167,561


Unrealized loss on derivatives


167,451



-



213,676



-















Adjusted EBITDA

$

1,970,033


$

6,279,421


$

5,874,110


$

13,584,110



Our adjusted EBITDA includes settlement income, net of settlement expenses, of $361,505 and $5,401,252 for the three months ended December 31, 2013 and 2012, respectively, and $361,505 and $11,145,895 for the years ended December 31, 2013 and 2012, respectively.


 

BLACK RIDGE OIL & GAS, INC.

BALANCE SHEETS










December 31,


December 31,


2013


2012

ASSETS








Current assets:




Cash and cash equivalents

$ 1,150,347


$ 1,417,340

Accounts receivable

1,905,467


856,233

Settlement receivable

-


2,500,000

Advances to operators

1,214,662


1,350,295

Prepaid expenses

26,142


47,155

Total current assets

4,296,618


6,171,023





Property and equipment:




Oil and natural gas properties, full cost method of accounting




Proved properties

79,361,432


35,248,983

Unproved properties

2,798,795


9,055,513

Other property and equipment

115,482


85,917

Total property and equipment

82,275,709


44,390,413

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

(9,513,434)


(5,793,184)

Total property and equipment, net

72,762,275


38,597,229





Debt issuance costs, net

772,883


657,702





Total assets

$ 77,831,776


$ 45,425,954









LIABILITIES AND STOCKHOLDERS' EQUITY








Current liabilities:




Accounts payable

$ 8,453,709


$ 2,953,526

Settlement payable

-


160,000

Settlement accounts payable, related party

-


116,234

Accrued expenses

4,813


61,666

Current portion of derivative instruments

139,065


-

Total current liabilities

8,597,587


3,291,426





Derivative instruments

74,611


-

Asset retirement obligations

160,665


67,145

Revolving credit facilities and long term debt, net of discounts of $2,645,582 and $-0-, respectively

30,556,301


5,748,844

Deferred tax liability

4,033,845


4,732,696





Total liabilities

43,423,009


13,840,111





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

33,072,795


29,847,212

Retained earnings

1,287,992


1,690,651

Total stockholders' equity

34,408,767


31,585,843





Total liabilities and stockholders' equity

$ 77,831,776


$ 45,425,954


 


BLACK RIDGE OIL & GAS, INC.

STATEMENTS OF OPERATIONS


















For the Three Months


For the Years


Ended December 31,


Ended December 31,


2013


2012


2013


2012









Oil and gas sales

$2,601,716


$1,690,079


$9,276,656


$6,022,540

Gain on settled derivatives

74,666


-


53,482


-

Losses on the mark-to-market of derivative instruments

(167,451)


-


(213,676)


-

Total revenues

$2,508,931


$1,690,079


$9,116,462


$6,022,540









Operating expenses:








Production expenses

332,663


221,927


1,145,686


649,603

Production taxes

292,921


165,792


1,015,907


692,527

General and administrative

584,470


575,126


2,299,757


3,530,643

Depletion of oil and gas properties

1,071,847


709,729


3,705,156


2,443,482

Accretion of discount on asset retirement obligations

4,245


1,213


9,019


4,557

Depreciation and amortization

6,547


5,811


24,001


24,206

Total operating expenses

2,292,693


1,679,598


8,199,526


7,345,018









Net operating income (loss)

216,238


10,481


916,936


(1,322,478)









Other income (expense):








Interest income

67


1,421


408


1,872

Interest (expense)

(856,760)


(388,981)


(2,380,359)


(1,193,278)

Settlement income

380,982


9,000,000


380,982


17,020,759

Settlement expense

(19,477)


(3,598,748)


(19,477)


(5,874,864)

Total other income (expense)

(495,188)


5,013,692


(2,018,446)


9,954,489









Income (loss) before provision for income taxes

(278,950)


5,024,173


(1,101,510)


8,632,011









Provision for income taxes

83,442


(2,089,971)


698,851


(3,720,601)









Net income (loss)

$(195,508)


$2,934,202


$(402,659)


$4,911,410

















Weighted average common shares outstanding - basic

47,979,990


47,979,990


47,979,990


47,789,225

Weighted average common shares outstanding - fully diluted

47,979,990


48,220,062


47,979,990


48,061,239









Net income (loss) per common share - basic

$ (0.00)


$ 0.06


$ (0.01)


$ 0.10

Net income (loss) per common share - fully diluted

$ (0.00)


$ 0.06


$ (0.01)


$ 0.10

 

BLACK RIDGE OIL & GAS, INC.


STATEMENTS OF CASH FLOWS











For the Years


Ended December 31,


2013


2012

CASH FLOWS FROM OPERATING ACTIVITIES




Net income (loss)

$ (402,659)


$ 4,911,410

Adjustments to reconcile net income (loss)




to net cash provided by operating activities:




Depletion of oil and gas properties

3,705,156


2,443,482

Depreciation and amortization

24,001


24,206

Amortization of debt issuance costs

749,920


190,580

Accretion of discount on asset retirement obligations

9,019


4,557

Losses on the mark-to-market of derivative instruments

213,676


-

Accrued payment in kind interest applied to long term debt

201,883


-

Amortization of original issue discount on debt

28,362


-

Amortization of debt discounts, warrants

199,632


-

Common stock issued for terminated oil and gas acquisition

-


438,539

Common stock warrants granted as financing costs

108,190


271,933

Common stock warrants granted as financing costs, related party

-


45,719

Common stock options issued to employees

643,817


849,909

Deferred income taxes

(698,851)


3,720,601

Decrease (increase) in current assets:




Accounts receivable

(1,049,234)


(183,230)

Settlement receivable

2,500,000


(2,500,000)

Prepaid expenses

21,013


(6,556)

Contingent consideration receivable

-


6,008,602

Increase (decrease) in current liabilities:




Accounts payable

164,527


119,610

Accounts payable, related parties

-


(9,206)

Settlement payable

(160,000)


160,000

Settlement payable, related parties

(116,234)


116,234

Accrued expenses

(56,853)


61,666

Royalties payable, related party

-


(300,431)

Net cash provided by operating activities

6,085,365


16,367,625





CASH FLOWS FROM INVESTING ACTIVITIES




Proceeds from sale of oil and gas properties

608,387


1,893,649

Purchases of oil and gas properties and development capital expenditures

(32,025,724)


(21,213,070)

Advances to operators

(882,604)


(1,977,188)

Purchases of other property and equipment

(38,472)


(7,428)

Net cash used in investing activities

(32,338,413)


(21,304,037)





CASH FLOWS FROM FINANCING ACTIVITIES




Advances from revolving credit facilities and long term debt

41,150,000


16,350,000

Repayments on revolving credit facilities

(14,298,844)


(10,601,156)

Debt issuance costs paid

(865,101)


(796,233)

Net cash provided by financing activities

25,986,055


4,952,611





NET CHANGE IN CASH

(266,993)


16,199

CASH AT BEGINNING OF PERIOD

1,417,340


1,401,141

CASH AT END OF PERIOD

$ 1,150,347


$ 1,417,340









SUPPLEMENTAL INFORMATION:




Interest paid

$ 1,104,688


$ 667,917

Income taxes paid

$ -


$ -





NON-CASH INVESTING AND FINANCING ACTIVITIES:




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

$ 5,335,656


$ 195,995

Advances to operators received in swap for oil and gas properties

$(1,200,000)


$ -

Advances to operators applied to development of oil and gas properties

$ 2,218,237


$ 626,893

Capitalized asset retirement costs, net of revision in estimate

$ 84,501


$ 58,688

Liabilities relieved to additional paid-in capital

$ -


$ 183,015

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

Brenda Blume, Director of Investor and Public Relations
952-582-4303

www.blackridgeoil.com

SOURCE Black Ridge Oil & Gas, Inc.