Black Ridge Oil & Gas Announces Third Quarter 2015 Results

Nov 12, 2015, 16:05 ET from Black Ridge Oil & Gas, Inc.

MINNETONKA, Minn., Nov. 12, 2015 /PRNewswire/ -- Black Ridge Oil & Gas, Inc. ("the Company") (OTCQB: ANFC), a growth-oriented exploration and production company focused on non-operated Bakken and Three Forks properties, today announced financial and operating results for the three and nine months ended September 30, 2015.

Third Quarter 2015 Company Highlights

  • Ended quarter with $26.65 million drawn from our senior secured facility, a net reduction of $3.1 million from the end of the second quarter of 2015
  • Monetized $6.3 million of hedges and used proceeds to pay down debt
  • Quarterly production increased 41% over the third quarter of 2014 to 98.9 thousand barrels of oil equivalent ("MBoe"), an average of approximately 1,075 barrels of oil equivalent per day ("Boe/d")
  • Oil and gas sales totaled $3.6 million, a decrease of 33% over the second quarter of 2015 and a decrease of 39% from the third quarter of 2014
  • Added 50 gross (1.92 net) wells, increasing our total producing well count to 341 gross (10.88 net), an increase of 48% over the third quarter of 2014
  • Recorded $9.0 million of adjusted EBITDA, including $6.3 million from the liquidation of derivative contracts prior to their contractual maturity
  • Recorded GAAP net loss for the quarter of $0.60 per diluted share, impacted by a non-cash impairment of $31.0 million ($0.65 per diluted share, net of tax effect). The impairment is primarily the result of low oil prices
  • Continued the development of the Teton project (1.76 net wells) with strong initial production rates

Liquidity Position and Borrowing Base

Black Ridge ended the quarter with $26.65 million drawn on its $34 million senior secured revolving credit facility. The borrowing base was adjusted by our lender as part of a regularly scheduled redetermination to $33 million effective October 1, 2015 and will adjust down to $32 million on November 16, 2015. The reduction in borrowing base is the net effect of lower commodity prices and monetization of hedges, substantially offset by Teton project development. The next redetermination date is scheduled for April 1, 2016. We currently have no obligations to enter into new hedging agreements, but may choose to opportunistically do so in accord with our lending partners. Until we see sustained improvement in oil prices, the Company's future acquisition and development activity is likely to be focused within the Merced joint venture. With limited development within the base business, the Company expects the current borrowing base and cash flows to meet our liquidity needs.

Teton Project Update and Production Guidance

In October 2015, 19 of the 23 wells in our Teton project were turned over to full production, with the remaining four wells scheduled to be turned over to production in mid-December once facilities are connected. All of the 19 wells are producing at rates near or above our expectations based on very positive flow-back rates achieved early in the second quarter. With the startup delay, the Teton project contributed only 199 boe/d during the third quarter. We expect production contribution to increase significantly during the fourth quarter.

Management Comment

"The Company is excited by the initial results from our Teton project and we look forward to full production and cash flow from this asset," said Ken DeCubellis, Chief Executive Officer. "As we look forward to the remainder of 2015 and into 2016, the Company's focus will be maintaining liquidity by allocating our free cash flow to debt reduction and finding acquisition opportunities for our joint venture with Merced."

Hedging Update

In the third quarter of 2015, the Company realized a $7,456,284 gain on settled derivatives, of which $1,201,284 was from settlements on their scheduled maturity dates and $6,255,000 was from the liquidation of our 2018, 2017, and the majority of our 2016 derivative contracts prior to their scheduled maturity dates. As of September 30, 2015, the Company's net derivative asset was $2,693,561. The following table summarizes the Company's open crude oil swap contracts as of September 30, 2015:



Oil


Weighted Average

Term


(barrels)


Price ($ per Bbl)

2015:





Q4


57,750


72.40

2016:





Q2


29,000


75.84

 

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 September 30, 2015:



Oil


Floor/Ceiling



Term


(Barrels)


Price (WTI)


Basis

Costless Collars – Crude Oil







10/01/2015 – 12/31/2015


9,000


$75.00/$95.60


NYMEX

01/01/2016 – 06/30/2016


3,334


$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


Nine Months Ended


September 30,


September 30,


2015


2014


2015


2014

Net Production:












Oil (Bbl)


86,533



62,603



249,593



164,570

Natural gas (Mcf)


74,279



44,639



244,974



106,458

Barrel of oil equivalent (Boe)


98,933



70,043



290,422



182,313













Average Sales Prices:












Oil (per Bbl)

$

37.83


$

84.17


$

43.86


$

87.71

Effect of oil hedges on average price (per Bbl)

$

13.88(a)


$

(1.12)


$

12.75(a)


$

(2.73)

Oil net of hedging (per Bbl)

$

51.71(a)


$

83.05


$

56.61(a)


$

84.98

Natural gas (per Mcf)

$

1.14


$

4.99


$

1.43


$

6.03

Realized price on a Boe basis, net of settled derivatives

$

46.10(a)


$

77.41


$

49.85(a)


$

80.23













Average Production Costs:












Oil (per Bbl)

$

9.99


$

10.27


$

11.74


$

10.31

Natural gas (per Mcf)

$

0.30


$

0.61


$

0.41


$

0.72

Barrel of oil equivalent (per Boe)

$

8.97


$

9.57


$

10.44


$

9.73

Production Taxes (per Boe)

$

3.34


$

8.41


$

4.03


$

8.70

General and Administrative Expense (per Boe)

$

7.63


$

9.85


$

7.90


$

11.49

Depletion, Depreciation and Accretion (per Boe)

$

18.10


$

32.69


$

25.42


$

33.10














(a)

Excludes the effect of derivatives settlement prior to their contractual settlement date.

 

Derivative Liquidation

During the third quarter of 2015, we settled all of our 2017 and 2018 derivative contracts and the majority of our 2016 derivative contracts prior to the expiration of their contractual maturities, resulting in cash proceeds totaling $6,255,000. The resulting gain is included in our gain on settled derivatives for the three and nine months ended September 30, 2015.

Third Quarter 2015 Financial Results

In the third quarter of 2015, oil and gas sales, excluding the impact of settled derivatives, were $3.4 million, a decrease of 39% as compared to the third quarter of 2014. The Company realized an average price of $37.83 per barrel of oil, before the effects of hedging, and $1.14 per mcf of gas, representing decreases of 55% and 77%, respectively, as compared to the third quarter of 2014. The impact of weaker commodity prices was partially offset by a 41% increase in production over the third quarter of 2014. The Company's production in the third quarter of 2015 was comprised of 87% oil and 13% natural gas and natural gas liquids, on a Boe basis.

For the third quarter of 2015, the Company realized a gain on settled derivatives of $7.5 million, compared to a loss of $0.1 million in the third quarter of 2014. The third quarter 2015 settlements include the $6.3 million gain from the derivative liquidation and $1.2 million realized gain from the settlement of derivatives upon their contracted expiration date. The Company had a mark-to-market derivative loss of $3.3 million in the third quarter of 2015 compared to a mark-to-market gain of $2.1 million in the third quarter of 2014. The mark-to-market derivative loss in the third quarter of 2015 was primarily driven by the conversion of unrealized gains to realized gains, partially offset by an increase in the value of remaining hedges in the portfolio.

Production expenses for the third quarter of 2015 were $0.9 million, or $8.97 per Boe, compared to $0.7 million, or $9.57 per Boe, for the third quarter of 2014. The decrease in production expense in the third quarter was primarily attributable to lower water disposal costs as much of the new production brought on in the third quarter is from wells with lower water cuts.

Production taxes for the third quarter of 2015 were $0.3 million, compared to $0.6 million, for the third quarter of 2014. Production taxes as a percent of oil and gas sales were 9.8% for the third quarter of 2015, compared to 10.7% for the third quarter of 2014.

Depletion, depreciation, amortization and accretion ("DD&A") was $1.8 million, or $18.10 per Boe, in the third quarter of 2015, compared to $2.3 million, or $32.69 per Boe, in the third quarter of 2014. The primary driver for the decrease in DD&A was the reduction in the full cost pool caused by the impairment recorded in the second quarter of 2015.

As a result of the currently prevailing low commodity prices and their effect on the proved reserve values of properties in 2015, we recorded a non-cash ceiling test impairment of $31.0 million in the third quarter of 2015. The Company did not have any impairment of its proved oil and gas properties in the third quarter of 2014. The impairment charge affected our reported net income but did not reduce our cash flow.

General and administrative expenses ("G&A") for the third quarter of 2015 were $0.8 million, or $7.63 per Boe, compared to $0.7 million, or $9.85 per Boe, for the third quarter of 2014. Cash G&A (non-GAAP, excludes stock-based compensation expense) was $0.6 million, or $6.09 per Boe, for the third quarter of 2015 compared to $0.5 million, or $7.79 per Boe, for the third quarter of 2014.

Interest expense, net of capitalized interest, was $1.7 million in the third quarter of 2015, compared to $1.4 million in the third quarter of 2014. The increase in interest expense was primarily due to additional borrowing to fund the Company's capital development program.

The income tax benefit recognized during the third quarter of 2015 was $-0- million, or 0.0% of the loss before income taxes, as compared to a net income tax expense of $0.7 million, or 37.0% of the loss before income taxes, in the third quarter of 2014. The lower effective tax rate in 2015 relates to a valuation allowance placed on the net deferred tax asset in the third quarter of 2015.

The Company recorded $9.0 million of adjusted EBITDA in the third quarter of 2015, which includes the liquidated derivative gain of $6.3 million. Adjusted EBITDA was $3.6 million for the third quarter of 2014. Adjusted EBITDA is a non-GAAP financial measure. Please refer to the reconciliation in this release for additional information about this measure.

Acreage and Drilling

As of September 30, 2015, the Company controlled approximately 8,509 net acres in the Williston Basin. Approximately 72% of the acreage is held by production with 341 gross (10.88 net) wells producing. Additionally, the Company had 0.26 net wells in development as of September 30, 2015.

Producing Wells

The following table sets forth wells in which Black Ridge holds a participating interest that were completed during the quarter ending September 30, 2015:

Well

Operator

Location

WI(1)

Kings Canyon 5-8-34UTF

Burlington Resources

McKenzie, ND

8.4%

Teton 5-8-10MBH

Burlington Resources

McKenzie, ND

8.4%

Kings Canyon 2-8-34UTFH

Burlington Resources

McKenzie, ND

8.4%

Kings Canyon 3-1-27MTFH

Burlington Resources

McKenzie, ND

8.4%

Kings Canyon 4-1-27MTFH

Burlington Resources

McKenzie, ND

8.4%

Kings Canyon 4-8-34MBH

Burlington Resources

McKenzie, ND

8.4%

Kings Canyon 4-8-34UTFH

Burlington Resources

McKenzie, ND

8.4%

Kings Canyon 6-1-27MBH

Burlington Resources

McKenzie, ND

8.4%

Kings Canyon 6-1-27MTFH

Burlington Resources

McKenzie, ND

8.4%

Kings Canyon 6-8-34UTFH

Burlington Resources

McKenzie, ND

8.4%

Kings Canyon 7-8-34MBH

Burlington Resources

McKenzie, ND

8.4%

Teton 2-8-10MBH

Burlington Resources

McKenzie, ND

8.4%

Teton 3-8-10MBH

Burlington Resources

McKenzie, ND

8.4%

Teton 5-1-3TFSH

Burlington Resources

McKenzie, ND

8.4%

Teton 6-8-10MBH

Burlington Resources

McKenzie, ND

8.4%

Teton 6-8-10TFSH

Burlington Resources

McKenzie, ND

8.4%

Teton 7-1-3TFSH

Burlington Resources

McKenzie, ND

8.4%

Teton 7-8-10MBH

Burlington Resources

McKenzie, ND

8.4%

Teton 8-8-10TFSH

Burlington Resources

McKenzie, ND

8.4%

Remingteton 8-8-10MBH

Burlington Resources

McKenzie, ND

6.2%

Thorp Federal 11X-28A

XTO

Dunn, ND

3.4%

LaCanyon 8-8-34MBH ULW

Burlington Resources

McKenzie, ND

2.1%

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

Hess

Mountrail, ND

1.6%

CCU Boxcar 44-22PH

Burlington Resources

Dunn, ND

0.8%

CCU Dakotan 1-7-17MBH

Burlington Resources

Dunn, ND

0.8%

CCU Dakotan 1-7-17TFH

Burlington Resources

Dunn, ND

0.8%

CCU Dakotan 2-7-17MBH

Burlington Resources

Dunn, ND

0.8%

CCU Dakotan 2-7-17TFH

Burlington Resources

Dunn, ND

0.8%

CCU Dakotan 3-8-17MBH

Burlington Resources

Dunn, ND

0.8%

CCU Dakotan 4-8-17TFH

Burlington Resources

Dunn, ND

0.8%

CCU Dakotan 5-8-17MBH

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 7-8-17MBH

Burlington Resources

Dunn, ND

0.8%

CCU Dakotan 7-8-17TFH

Burlington Resources

Dunn, ND

0.8%

CCU Gopher 1-2-15TFH

Burlington Resources

Dunn, ND

0.8%

CCU Gopher 2-2-15MBH

Burlington Resources

Dunn, ND

0.8%

CCU Olympian 31-2MBH

Burlington Resources

Dunn, ND

0.8%

CCU Powell 41-29TFH

Burlington Resources

Dunn, ND

0.8%

CCU Red River 8-2-15MBH

Burlington Resources

Dunn, ND

0.8%

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

Whiting

Williams, ND

0.6%

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

Whiting

Williams, ND

0.6%

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

Whiting

Williams, ND

0.6%

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

Whiting

Williams, ND

0.6%

Burr Federal 10-26H

Continental

Mountrail, ND

0.5%

Burr Federal 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%

Burr Federal 9-26H1

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.

 

"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 September 30, 2015:

Well

Operator

Location

WI(1)

EN-VP AND R- 154-94-2536H-5

Hess

Mountrail, ND

3.1%

EN-VP AND R- 154-94-2536H-6

Hess

Mountrail, ND

3.1%

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

Whiting

Williams, ND

1.0%

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

Whiting

Williams, ND

1.0%

Aaberg 8-5N-1H

Mountain Divide

Divide, ND

0.8%

CCU Atlantic Express 13-19TFH

Burlington Resources

Dunn, ND

0.8%

CCU Atlantic Express 23-19MBH

Burlington Resources

Dunn, ND

0.8%

CCU Atlantic Express 41-30MBH

Burlington Resources

Dunn, ND

0.8%

CCU Audubon 3-7-22TFH

Burlington Resources

Dunn, ND

0.8%

CCU Bison Point 24-34MBH

Burlington Resources

Dunn, ND

0.8%

CCU Bison Point 24-34TFH

Burlington Resources

Dunn, ND

0.8%

CCU Bison Point 34-34MBH

Burlington Resources

Dunn, ND

0.8%

CCU Bison Point 34-34TFH

Burlington Resources

Dunn, ND

0.8%

CCU Boxcar 4-7-22TFH

Burlington Resources

Dunn, ND

0.8%

CCU Burner 31-26TFH

Burlington Resources

Dunn, ND

0.8%

CCU Golden Creek 34-23TFH

Burlington Resources

Dunn, ND

0.8%

CCU Olympian 21-2MBH

Burlington Resources

Dunn, ND

0.8%

CCU Olympian 31-2TFH

Burlington Resources

Dunn, ND

0.8%

CCU Pacific Express 12-19TFH

Burlington Resources

Dunn, ND

0.8%

CCU Plymouth 11-29MBH

Burlington Resources

Dunn, ND

0.8%

CCU Plymouth 11-29TFH

Burlington Resources

Dunn, ND

0.8%

CCU Plymouth 21-29TFH

Burlington Resources

Dunn, ND

0.8%

CCU Red River 7-2-15TFH

Burlington Resources

Dunn, ND

0.8%

Jersey 1-6H

Continental

Mountrail, ND

0.8%

Jersey 2-6H2

Continental

Mountrail, ND

0.8%

Jersey 3-6H1

Continental

Mountrail, ND

0.8%

Jersey 5-6H

Continental

Mountrail, ND

0.8%



(1)

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

 

Adjusted Net 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 (loss), excluding (i) net income (loss) on the mark-to-market of derivatives, net of tax and (ii) impairment of oil and gas properties, net of tax. We define Adjusted EBITDA as income (loss) before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion and amortization, (iv) impairment of oil and gas properties, (v) accretion of abandonment liability, (vi) income (losses) on the mark-to-market of derivatives, and (vii) non-cash expenses relating to share based payments recognized under ASC Topic 718. We believe the use of non-GAAP financial measures provides useful information to investors regarding our current financial performance; however, Adjusted Net 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 (loss), GAAP, is included below:

Reconciliation of Net Loss to Adjusted Net Income (Loss)


Three Months Ended


Nine Months Ended


September 30,


September 30,


2015


2014


2015


2014

Net income (loss)

$

(28,920,487)


$

1,190,716


$

(48,863,061)


$

265,796

Add back:












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


3,297,358



(1,352,798)



4,300,184



(663,639)

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


30,995,000



-



46,318,000



-

Adjusted net income (loss)

$

5,371,871


$

(162,082)


$

1,755,123


$

(397,843)













Weighted average common shares outstanding - basic


47,979,990



47,979,990



47,979,990



47,979,990













Weighted average common shares outstanding - fully diluted


47,979,990



49,588,039



47,979,990



49,824,437













Net income (loss) per common share – basic

$

(0.60)


$

0.02


$

(1.02)


$

0.01

Add:












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


0.07



(0.03)



0.09



(0.01)

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


0.65



-



0.97



-

Adjusted net income (loss) per common share – basic

$

0.11


$

(0.00)


$

0.04


$

(0.01)













Net income (loss) per common share – fully diluted

$

(0.60)


$

0.02


$

(1.02)


$

0.01

Add:












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


0.07



(0.03)



0.09



(0.01)

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


0.65



-



0.97



-

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

$

0.11


$

(0.00)


$

0.04


$

(0.01)



(a)

Adjusted to reflect tax expense (benefit), computed based on our effective tax rate of approximately 0% and 12% for the three and nine months ended September 30, 2015, and 37% in both the three and nine months ended September 30, 2014, consisting of $-0- and $795,000 for the three month ended September 30, 2015 and 2014, respectively, and ($586,000) and $389,000 for the nine months ended September 30, 2015 and 2014, respectively.



(b)

Adjusted to reflect tax expense, computed based on our effective tax rate of approximately 0% and 12% for the three and nine months ended September 30, 2015, and 37% in both the three and nine months ended September 30, 2014, consisting of $8,369,000 and $-0- for the three month ended September 30, 2015 and 2014, respectively, and $14,211,000 and $-0- for the nine months ended September 30, 2015 and 2014, respectively.

 

Reconciliation of Net Loss to Adjusted EBITDA


Three Months Ended


Nine Months Ended


September 30,


September 30,


2015


2014


2015


2014

Net income (loss)

$     (28,920,487)


$  1,190,716


$     (48,863,061)


$      265,796

Add back:








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

1,519,058


1,280,674


4,311,715


3,346,655

Income tax provision

-


700,587


(6,593,040)


110,849

Depreciation, depletion, and amortization

1,782,590


2,283,917


7,358,642


6,018,507

Impairment of oil and gas properties

30,995,000


-


52,634,000


-

Accretion of abandonment liability

8,039


5,833


23,900


15,486

Share based compensation

314,374


302,961


949,888


901,964

Loss (gain) on mark-to market of derivatives

3,297,358


(2,147,798)


4,886,184


(1,052,639)









Adjusted EBITDA

$        8,995,932


$  3,616,890


$      14,708,228


$    9,606,618

 

Our adjusted EBITDA for the nine month periods ended September 30, 2015 includes income from the Dahl Federal well that was recognized in the current period based on activity in prior periods of $1,027,995.

BLACK RIDGE OIL & GAS, INC.

CONDENSED BALANCE SHEETS










September 30,


December 31,


2015


2014

ASSETS

 (Unaudited)







Current assets:




Cash and cash equivalents

$        58,599


$          94,682

Derivative instruments, current

2,693,561


3,571,803

Accounts receivable

3,861,923


5,740,171

Prepaid expenses

49,107


41,387

Total current assets

6,663,190


9,448,043





Property and equipment:




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




Proved properties

128,083,460


112,418,105

Unproved properties

803,718


591,121

Other property and equipment

139,004


139,004

Total property and equipment

129,026,182


113,148,230

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

(78,895,166)


(18,902,524)

Total property and equipment, net

50,131,016


94,245,706





Derivative instruments, long-term

-


4,007,942

Debt issuance costs, net

463,792


701,019





Total assets

$ 57,257,998


$ 108,402,710









LIABILITIES AND STOCKHOLDERS' EQUITY








Current liabilities:




Accounts payable

$   8,438,772


$   10,291,262

Accrued expenses

65,207


57,435

Total current liabilities

8,503,979


10,348,697





Asset retirement obligations

353,095


286,804

Revolving credit facilities and long term debt, net of discounts of $1,461,093 and $2,072,483, respectively

57,458,543


51,834,603

Deferred tax liability

-


6,593,040





Total liabilities

66,315,617


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

34,117,590


33,651,714

Retained earnings (accumulated deficit)

(43,223,189)


5,639,872

Total stockholders' equity

(9,057,619)


39,339,566





Total liabilities and stockholders' equity

$ 57,257,998


$ 108,402,710

 



BLACK RIDGE OIL & GAS, INC.

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)


















For the Three Months


For the Nine Months


Ended September 30,


Ended September 30,


2015


2014


2015


2014









Oil and gas sales

$  3,359,684


$  5,492,326


$11,296,220


$15,076,743

Gain (loss) on settled derivatives

7,456,284


(70,253)


9,436,903


(449,135)

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

(3,297,358)


2,147,798


(4,886,184)


1,052,639

Total revenues

7,518,610


7,569,871


15,846,939


15,680,247









Operating expenses:








Production expenses

887,187


670,404


3,030,707


1,773,458

Production taxes

330,186


588,923


1,171,530


1,585,755

General and administrative

754,788


690,189


2,295,241


2,095,071

Depletion of oil and gas properties

1,778,580


2,275,703


7,346,356


5,994,180

Impairment of oil and gas properties

30,995,000


-


52,634,000


-

Accretion of discount on asset retirement obligations

8,039


5,833


23,900


15,486

Depreciation and amortization

4,010


8,214


12,286


24,327

Total operating expenses

34,757,790


4,239,266


66,514,020


11,488,277









Net operating income (loss)

(27,239,180)


3,330,605


(50,667,081)


4,191,970









Other income (expense):








Other income

-


-


6,707


-

Interest income

-


972


-


972

Interest (expense)

(1,681,307)


(1,440,274)


(4,795,727)


(3,816,297)

Total other income (expense)

(1,681,307)


(1,439,302)


(4,789,020)


(3,815,325)









Income (loss) before provision for income taxes

(28,920,487)


1,891,303


(55,456,101)


376,645









Provision for income taxes

-


(700,587)


6,593,040


(110,849)









Net income (loss)

$(28,920,487)


$  1,190,716


$(48,863,061)


$     265,796

















Weighted average common shares outstanding - basic

47,979,990


47,979,990


47,979,990


47,979,990

Weighted average common shares outstanding - fully diluted

47,979,990


49,588,039


47,979,990


49,824,437









Net loss per common share - basic

$            (0.60)


$           0.02


$           (1.02)


$           0.01

Net loss per common share - fully diluted

$            (0.60)


$           0.02


$           (1.02)


$           0.01

 

 

BLACK RIDGE OIL & GAS, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)










For the Nine Months


Ended September 30,


2015


2014

CASH FLOWS FROM OPERATING ACTIVITIES




Net income (loss)

$(48,863,061)


$     265,796

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




Depletion of oil and gas properties

7,346,356


5,994,180

Depreciation and amortization

12,286


24,327

Amortization of debt issuance costs

287,227


229,936

Accretion of discount on asset retirement obligations

23,900


15,486

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

4,886,184


(1,052,639)

Accrued payment in kind interest applied to long term debt

962,550


787,344

Amortization of original issue discount on debt

127,378


102,566

Amortization of debt discounts, warrants

484,012


468,670

Common stock options issued to employees and directors

465,876


433,294

Deferred income taxes

(6,593,040)


110,849

Impairment of oil and natural gas properties

52,634,000


-

Decrease (increase) in current assets:




Accounts receivable

1,878,248


(1,233,582)

Prepaid expenses

(7,720)


(45,916)

Increase (decrease) in current liabilities:




Accounts payable

153,024


223,779

Accrued expenses

7,772


61,423

Net cash provided by operating activities

13,804,992


6,385,513





CASH FLOWS FROM INVESTING ACTIVITIES




Proceeds from sale or swap of oil and gas properties

127,348


1,360,920

Purchases of oil and gas properties and development capital expenditures

(17,968,423)


(17,410,744)

Advances to operators

-


(5,742,272)

Purchases of other property and equipment

-


(11,131)

Net cash used in investing activities

(17,841,075)


(21,803,227)





CASH FLOWS FROM FINANCING ACTIVITIES




Advances from revolving credit facilities and long term debt

14,000,000


24,150,000

Repayments on revolving credit facilities

(9,950,000)


(9,600,000)

Debt issuance costs

(50,000)


(254,394)

Net cash provided by financing activities

4,000,000


14,295,606





NET CHANGE IN CASH

(36,083)


(1,122,108)

CASH AT BEGINNING OF PERIOD

94,682


1,150,347

CASH AT END OF PERIOD

$       58,599


$       28,239









SUPPLEMENTAL INFORMATION:




Interest paid

$   3,292,793


$  2,411,463

Income taxes paid

$                  -


$                 -





NON-CASH INVESTING AND FINANCING ACTIVITIES:




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

$ (2,005,514)


$  3,821,375

Advances to operators applied to development of oil and gas properties

$                 -


$  4,285,575

Capitalized asset retirement costs, net of revision in estimate

$        42,391


$       61,815

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.

Make sure you are first to receive timely information on Black Ridge Oil & Gas when it hits the newswire. Sign up for Black Ridge's email news alert system today at http://ir.stockpr.com/blackridgeoil/email-alerts

Contact
Black Ridge Oil & Gas, Inc.

Ken DeCubellis, Chief Executive Officer
952-426-1241

www.blackridgeoil.com

 

SOURCE Black Ridge Oil & Gas, Inc.



RELATED LINKS

http://www.blackridgeoil.com