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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

 QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE

ACT OF 1934

 

For the quarterly period ended July 31, 2015

 

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE

ACT OF 1934

 

For the transition period from _________ to _________

 

Commission file number 001-34945

 

TRIANGLE PETROLEUM CORPORATION

(Exact Name of Registrant as Specified in Its Charter)

 

 

 

 

 

Delaware

   

 

98-0430762

(State or Other Jurisdiction of

Incorporation or Organization)

   

 

(I.R.S. Employer

Identification No.)

 

1200 17th Street, Suite 2600

Denver, CO 80202

(Address of Principal Executive Offices)

 

(303) 260-7125

(Registrant’s telephone number, including area code)

 

(Former name, former address and former fiscal year, if changed since last report)

 

Indicate by check mark whether the registrant:  (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes   No

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes   No

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of large accelerated filer, accelerated filer, and smaller reporting company in Rule 12b-2 of the Exchange Act.

 

 

 

 

 

 Large accelerated filer

 Accelerated filer

 Non-accelerated filer

 Smaller reporting company

(Do not check if a smaller reporting company)

   

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes    No

 

As of September 3, 2015, there were 75,504,924 shares of the registrant’s common stock outstanding.

 

 

 

 


 

TRIANGLE PETROLEUM CORPORATION AND SUBSIDIARIES

 

INDEX TO FORM 10-Q FOR THE QUARTERLY PERIOD ENDED JULY 31, 2015

 

April

 

 

 

 

 

 

 

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS 

 

 

PART I.    FINANCIAL INFORMATION 

   

   

   

 

   

ITEM 1.

FINANCIAL STATEMENTS (UNAUDITED)

   

   

   

 

   

   

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

 

 

   

   

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

   

   

   

 

   

   

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

 

 

   

   

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

   

   

   

 

   

   

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

   

   

   

   

   

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

24 

 

 

 

 

   

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

35 

   

   

   

 

   

ITEM 4.

CONTROLS AND PROCEDURES

36 

   

   

   

 

PART II.   OTHER INFORMATION 

37 

   

   

   

 

   

ITEM 1.

LEGAL PROCEEDINGS

37 

 

 

 

 

   

ITEM 1A.

RISK FACTORS

37 

 

 

 

 

   

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

37 

 

 

 

 

   

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

38 

 

 

 

 

   

ITEM 4.

MINE SAFETY DISCLOSURES 

38 

 

 

 

 

   

ITEM 5.

OTHER INFORMATION

38 

 

 

 

 

   

ITEM 6.

EXHIBITS

39 

   

   

   

 

SIGNATURES 

40 

 

 

 

 


 

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

 

Certain statements contained in this report and other materials we file with the U.S. Securities and Exchange Commission (“SEC”), or in other written or oral statements made or to be made by us, other than statements of historical fact, are forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements reflect our current expectations or forecasts of future events. Words such as “anticipates,” “expects,” “intends,” “plans,” “predicts,” “believes,” “seeks,” “estimates,” “could,” “would,” “will,” “may,” “can,” “continue,” “potential,” “likely,” “should,” and the negative of these terms or other comparable terminology, often identify forward-looking statements. Statements in this quarterly report that are not statements of historical facts are hereby identified as forward-looking statements for the purpose of the safe harbor provided by Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and Section 27A of the Securities Act of 1933, as amended (the “Securities Act”).

 

These forward-looking statements include, but are not limited to, statements about our:

 

·

future capital expenditures and performance;

·

future operating results;

·

anticipated drilling and development;

·

drilling results;

·

results of acquisitions;

·

relationships with partners; and

·

plans for our subsidiaries.

 

Actual results or developments may be different than we anticipate or may have unanticipated consequences to, or effects on, us or our business or operations. All of the forward-looking statements made in this report are qualified by the discussion of risks and uncertainties under Risk Factors in our Annual Report on Form 10-K for the fiscal year ended January 31, 2015, and in our other public filings with the SEC. Although the expectations reflected in the forward-looking statements are based on our current beliefs and expectations, undue reliance should not be placed on any such forward-looking statements due to the risks and uncertainties noted above and because such statements speak only as of the date hereof. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. All forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this report and in our future reports filed with the SEC. In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this report may not occur.

 

1


 

PART I.  FINANCIAL INFORMATION

 

ITEM 1.  FINANCIAL STATEMENTS (UNAUDITED)

 

 

Triangle Petroleum Corporation

Condensed Consolidated Balance Sheets (Unaudited)

(In thousands, except share data)

 

 

 

 

 

 

 

 

 

    

January 31, 2015

    

July 31, 2015

ASSETS

CURRENT ASSETS

 

 

 

 

 

 

Cash and cash equivalents

 

$

67,871

 

$

45,870

Accounts receivable

 

 

171,911

 

 

116,159

Commodity derivatives

 

 

54,775

 

 

26,677

Other current assets

 

 

14,952

 

 

8,947

Total current assets

 

 

309,509

 

 

197,653

 

 

 

 

 

 

 

PROPERTY, PLANT AND EQUIPMENT, AT COST

 

 

 

 

 

 

Oil and natural gas properties, full cost method of accounting

 

 

 

 

 

 

Proved properties

 

 

1,159,584

 

 

1,302,145

Unproved properties and properties under development, not being amortized

 

 

142,896

 

 

112,918

Total oil and natural gas properties

 

 

1,302,480

 

 

1,415,063

Accumulated amortization

 

 

(176,390)

 

 

(627,296)

Net oil and natural gas properties

 

 

1,126,090

 

 

787,767

Oilfield services equipment, net

 

 

87,549

 

 

79,997

Other property and equipment, net

 

 

47,367

 

 

48,825

Net property, plant and equipment

 

 

1,261,006

 

 

916,589

 

 

 

 

 

 

 

OTHER ASSETS

 

 

 

 

 

 

Deferred loan costs

 

 

14,038

 

 

13,601

Equity investment

 

 

64,411

 

 

73,709

Commodity derivatives

 

 

 —

 

 

2,689

Other

 

 

5,906

 

 

5,716

Total other assets

 

 

84,355

 

 

95,715

 

 

 

 

 

 

 

Total assets

 

$

1,654,870

 

$

1,209,957

 

See notes to condensed consolidated financial statements.

2


 

Triangle Petroleum Corporation

Condensed Consolidated Balance Sheets (Unaudited)

(In thousands, except share data)

 

 

 

 

 

 

 

 

 

    

January 31, 2015

    

July 31, 2015

LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES

 

 

 

 

 

 

Accounts payable and accrued capital expenditures

 

$

176,182

 

$

130,698

Other accrued liabilities

 

 

73,440

 

 

57,667

Current portion of long-term debt

 

 

503

 

 

677

Interest payable

 

 

2,250

 

 

1,725

Deferred income taxes

 

 

19,467

 

 

 —

Total current liabilities

 

 

271,842

 

 

190,767

 

 

 

 

 

 

 

LONG-TERM LIABILITIES

 

 

 

 

 

 

5% convertible note

 

 

135,877

 

 

139,295

Borrowings on credit facilities

 

 

224,159

 

 

259,192

TUSA 6.75% notes

 

 

429,500

 

 

425,889

Other notes and mortgages payable

 

 

10,102

 

 

12,687

Deferred income taxes

 

 

33,974

 

 

 —

Other

 

 

4,398

 

 

4,435

Total liabilities

 

 

1,109,852

 

 

1,032,265

 

 

 

 

 

 

 

COMMITMENTS AND CONTINGENCIES

 

 

 

 

 

 

 

 

 

 

 

 

 

STOCKHOLDERS' EQUITY

 

 

 

 

 

 

Common stock, $0.00001 par value, 140,000,000 shares authorized; 75,174,442 and 75,488,871 shares issued and outstanding at January 31, 2015 and July 31, 2015, respectively

 

 

1

 

 

1

Additional paid-in capital

 

 

545,017

 

 

551,236

Retained earnings (accumulated deficit)

 

 

 —

 

 

(373,545)

Total stockholders' equity

 

 

545,018

 

 

177,692

 

 

 

 

 

 

 

Total liabilities and stockholders’ equity

 

$

1,654,870

 

$

1,209,957

 

See notes to condensed consolidated financial statements.

 

3


 

Triangle Petroleum Corporation

Condensed Consolidated Statements of Operations (Unaudited)

(In thousands, except per share data)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended

 

For the Six Months Ended

 

 

July 31,

 

July 31,

 

    

2014

    

2015

    

2014

 

2015

REVENUES:

 

 

 

 

 

 

 

 

 

 

 

 

Oil, natural gas and natural gas liquids sales

 

$

80,506

 

$

55,263

 

$

141,340

 

 

103,041

Oilfield services

 

 

61,483

 

 

54,470

 

 

100,431

 

 

124,980

Total revenues

 

 

141,989

 

 

109,733

 

 

241,771

 

 

228,021

EXPENSES:

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

 

6,698

 

 

11,369

 

 

11,424

 

 

22,278

Gathering, transportation and processing

 

 

3,733

 

 

6,641

 

 

7,535

 

 

12,989

Production taxes

 

 

8,677

 

 

5,449

 

 

15,025

 

 

10,236

Depreciation and amortization

 

 

26,707

 

 

32,244

 

 

47,994

 

 

70,050

Impairment of oil and natural gas properties

 

 

 —

 

 

206,000

 

 

 —

 

 

398,000

Accretion of asset retirement obligations

 

 

40

 

 

90

 

 

65

 

 

147

Oilfield services

 

 

43,554

 

 

46,719

 

 

71,264

 

 

112,183

General and administrative, net of amounts capitalized

 

 

14,091

 

 

14,589

 

 

27,492

 

 

29,448

Total operating expenses

 

 

103,500

 

 

323,101

 

 

180,799

 

 

655,331

 

 

 

 

 

 

 

 

 

 

 

 

 

INCOME (LOSS) FROM OPERATIONS

 

 

38,489

 

 

(213,368)

 

 

60,972

 

 

(427,310)

 

 

 

 

 

 

 

 

 

 

 

 

 

OTHER INCOME (EXPENSE):

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense, net

 

 

(4,218)

 

 

(9,866)

 

 

(6,890)

 

 

(18,972)

Amortization of deferred loan costs

 

 

(1,167)

 

 

(731)

 

 

(1,359)

 

 

(1,347)

Gain on extinguishment of debt

 

 

 —

 

 

1,156

 

 

 —

 

 

1,156

Realized commodity derivative gains (losses)

 

 

(2,954)

 

 

17,016

 

 

(3,772)

 

 

36,484

Unrealized commodity derivative gains (losses)

 

 

2,033

 

 

8,033

 

 

(2,605)

 

 

(25,409)

Equity investment income (loss)

 

 

190

 

 

1,210

 

 

64

 

 

1,398

Gain (loss) on equity investment derivatives

 

 

(7,534)

 

 

4,516

 

 

2,920

 

 

4,516

Gain on Caliber capital transactions

 

 

 —

 

 

 —

 

 

 —

 

 

2,880

Other income

 

 

52

 

 

(1,312)

 

 

114

 

 

(382)

Total other income (expense)

 

 

(13,598)

 

 

20,022

 

 

(11,528)

 

 

324

 

 

 

 

 

 

 

 

 

 

 

 

 

INCOME (LOSS) BEFORE INCOME TAXES

 

 

24,891

 

 

(193,346)

 

 

49,444

 

 

(426,986)

 

 

 

 

 

 

 

 

 

 

 

 

 

INCOME TAX PROVISION (BENEFIT)

 

 

10,339

 

 

 —

 

 

20,350

 

 

(53,441)

 

 

 

 

 

 

 

 

 

 

 

 

 

NET INCOME (LOSS)

 

$

14,552

 

$

(193,346)

 

$

29,094

 

$

(373,545)

   

 

 

 

 

 

 

 

 

 

 

 

 

Earnings (loss) per common share outstanding:

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

0.17

 

$

(2.56)

 

$

0.34

 

$

(4.96)

Diluted

 

$

0.15

 

$

(2.56)

 

$

0.30

 

$

(4.96)

   

 

 

 

 

 

 

 

 

 

 

 

 

Weighted average common shares outstanding:

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

 

86,172

 

 

75,410

 

 

86,064

 

 

75,334

Diluted

 

 

103,774

 

 

75,410

 

 

103,511

 

 

75,334

 

See notes to condensed consolidated financial statements.

 

4


 

Triangle Petroleum Corporation

Condensed Consolidated Statements of Cash Flows (Unaudited)

(In thousands)

 

 

 

 

 

 

 

 

 

 

For the Six Months Ended July 31,

 

    

2014

    

2015

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

 

Net income (loss)

 

$

29,094

 

$

(373,545)

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

 

 

 

 

 

 

Depreciation and amortization

 

 

47,994

 

 

70,050

Impairment of oil and natural gas properties

 

 

 —

 

 

398,000

Share-based compensation

 

 

3,815

 

 

6,134

Interest expense paid-in-kind on 5% convertible note

 

 

3,252

 

 

3,418

Amortization of deferred loan costs

 

 

1,359

 

 

1,347

Gain on extinguishment of debt

 

 

 —

 

 

(1,156)

Accretion of asset retirement obligations

 

 

65

 

 

147

Unrealized commodity derivative (gains) losses

 

 

2,605

 

 

25,409

Equity investment (income) loss

 

 

(64)

 

 

(1,398)

Gain on equity investment derivatives

 

 

(2,920)

 

 

(4,516)

Gain on Caliber capital transactions

 

 

 —

 

 

(2,880)

Deferred income taxes

 

 

19,800

 

 

(53,441)

Changes in related current assets and current liabilities:

 

 

 

 

 

 

Accounts receivable

 

 

(44,363)

 

 

55,752

Other current assets

 

 

(581)

 

 

6,005

Accounts payable and accrued liabilities

 

 

2,994

 

 

(48,345)

Asset retirement expenditures

 

 

(136)

 

 

(377)

Other

 

 

(1,068)

 

 

(559)

Cash provided by operating activities

 

 

61,846

 

 

80,045

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

 

Oil and natural gas property expenditures

 

 

(149,479)

 

 

(128,734)

Acquisitions of oil and natural gas properties

 

 

(131,368)

 

 

(243)

Purchases of oilfield services equipment

 

 

(24,579)

 

 

(8,657)

Purchases of other property and equipment

 

 

(3,080)

 

 

(4,208)

Sale of oil and natural gas properties

 

 

 —

 

 

6,000

Other

 

 

58

 

 

15

Cash used in investing activities

 

 

(308,448)

 

 

(135,827)

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

 

Proceeds from credit facilities

 

 

245,116

 

 

110,810

Repayments of credit facilities

 

 

(410,015)

 

 

(75,777)

Proceeds from notes payable

 

 

450,000

 

 

3,035

Repayments of other notes and mortgages payable

 

 

(199)

 

 

(298)

Early extinguishment of repurchased debt

 

 

 —

 

 

(2,455)

Debt issuance costs

 

 

(10,331)

 

 

(910)

Payments to settle tax on vested restricted stock units

 

 

(2,192)

 

 

(624)

Cash provided by financing activities

 

 

272,379

 

 

33,781

 

 

 

 

 

 

 

NET INCREASE (DECREASE) IN CASH AND EQUIVALENTS

 

 

25,777

 

 

(22,001)

CASH AND EQUIVALENTS, BEGINNING OF PERIOD

 

 

81,750

 

 

67,871

CASH AND EQUIVALENTS, END OF PERIOD

 

$

107,527

 

$

45,870

 

See notes to condensed consolidated financial statements.

 

 

 

5


 

Triangle Petroleum Corporation

Condensed Consolidated Statement of Stockholders’ Equity (Unaudited)

For the Six Months Ended July 31, 2015

(in thousands, except share data)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Retained

 

 

 

 

 

Shares of

 

Common

 

Additional

 

Earnings

 

 

 

 

 

Common

 

Stock at

 

Paid-in

 

(Accumulated

 

Total

 

    

Stock

    

Par Value

    

Capital

    

Deficit)

    

Equity

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance - January 31, 2015

 

75,174,442

 

$

1

 

$

545,017

 

$

 —

 

$

545,018

Vesting of restricted stock units (net of shares surrendered for taxes)

 

314,429

 

 

 —

 

 

(624)

 

 

 —

 

 

(624)

Share-based compensation

 

 —

 

 

 —

 

 

6,843

 

 

 —

 

 

6,843

Net income (loss) for the period

 

 —

 

 

 —

 

 

 —

 

 

(373,545)

 

 

(373,545)

Balance - July 31, 2015

 

75,488,871

 

$

1

 

$

551,236

 

$

(373,545)

 

$

177,692

 

 

See notes to condensed consolidated financial statements.

 

 

 

6


 

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

 

1.  DESCRIPTION OF BUSINESS

 

Triangle Petroleum Corporation (“Triangle,” the “Company,” “we,” “us,” “our,” or “ours”) is an independent energy holding company with three principal lines of business: oil and natural gas exploration, development, and production; oilfield services; and midstream services.

 

We hold leasehold interests and conduct our operations in the Williston Basin of North Dakota and Montana. Our core focus area is predominantly located in McKenzie and Williams Counties, North Dakota, and eastern Roosevelt and Sheridan Counties, Montana. We conduct our exploration and production operations through our wholly-owned subsidiary, Triangle USA Petroleum Corporation (“TUSA”).

 

In June 2011, we formed RockPile Energy Services, LLC (“RockPile”), a wholly-owned subsidiary, which provides oilfield and complementary well completion services to oil and natural gas exploration and production companies predominantly in the Williston Basin. RockPile began operations in July 2012.

 

In September 2012, through our wholly-owned subsidiary, Triangle Caliber Holdings, LLC, we formed Caliber Midstream Partners, L.P. (“Caliber”), an unconsolidated joint venture with First Reserve Energy Infrastructure Fund. Caliber was formed for the purpose of providing oil, natural gas and water transportation and related services to oil and natural gas exploration and production companies in the Williston Basin.

 

The Company, through its wholly-owned subsidiary, Elmworth Energy Corporation (“Elmworth”), previously conducted insignificant exploration and production activities in Canada. Elmworth has since sold all leasehold interests except for acreage in the Maritimes Basin of Nova Scotia. Elmworth has ceased all exploration and production activities in Canada except for reclaiming five wells, the drilling site and brine ponds on its Nova Scotia acreage. Elmworth has no proved reserves and its oil and natural gas properties were fully impaired as of January 31, 2012.

 

2.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

Basis of Presentation. These unaudited condensed consolidated financial statements and related notes are presented in accordance with accounting principles generally accepted in the United States of America (“GAAP”), and are expressed in U.S. dollars. Preparation in accordance with GAAP requires us to (i) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and by the Securities and Exchange Commission (“SEC”), and (ii) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, and other disclosed amounts.

 

Certain information and footnote disclosures normally included in our annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to SEC rules and regulations. We believe the disclosures made are adequate to make the information not misleading. We recommend that these unaudited condensed consolidated financial statements be read in conjunction with our audited consolidated financial statements and notes included in our Annual Report on Form 10-K for the fiscal year ended January 31, 2015, as filed with the SEC (“Fiscal 2015 Form 10-K”). In the opinion of management, all material adjustments considered necessary for a fair presentation of the Company’s interim results have been reflected. All such adjustments are considered to be of a normal recurring nature. The results for interim periods are not necessarily indicative of annual results.

 

No condensed consolidated statement of comprehensive income (loss) is presented because the Company had no comprehensive income or loss activity in the periods presented.

 

Use of Estimates. In the course of preparing its condensed consolidated financial statements, management makes various assumptions, judgments, and estimates to determine the reported amount of assets, liabilities, revenue, and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established. Significant areas requiring the use of assumptions, judgments and estimates include (i) oil and natural gas reserves; (ii) cash flow estimates used in ceiling tests of oil and natural gas properties; (iii) depreciation and amortization; (iv) impairment of unproved properties and other assets; (v) assigning fair value and allocating purchase price in connection with business combinations; (vi) accrued revenue and related receivables;

7


 

(vii) valuation of commodity derivative instruments and equity derivative instruments; (viii) accrued expenses and related liabilities; (ix) valuation of share-based payments and (x) income taxes. Although management believes these estimates are reasonable, actual results could differ from these estimates. The Company has evaluated subsequent events and transactions for matters that may require recognition or disclosure in these condensed consolidated financial statements.

 

Principles of Consolidation. The accounts of Triangle and its wholly-owned subsidiaries are presented in the accompanying condensed consolidated financial statements. All significant intercompany transactions and balances are eliminated in consolidation. Triangle generally uses the equity method of accounting for investments in entities in which Triangle has an ownership between 20% and 50% and exercises significant influence. The investment in Caliber is accounted for utilizing the equity method of accounting.  

 

Oil and Natural Gas Properties. We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitation and development costs of oil and natural gas properties. Once we incur costs, they are recorded in the amortizable pool of proved properties or in unproved properties, collectively, the full cost pool. We review our unproved oil and natural gas property costs on a quarterly basis to assess for impairment or the need to transfer unproved costs to proved properties as a result of extensions or discoveries from drilling operations.

 

At the end of each quarterly period, we must compute a limitation on capitalized costs, which is equal to the sum of the present value of estimated future net revenues from our proved reserves by applying the average price as prescribed by the SEC (unweighted arithmetic average of commodity prices in effect on the first day of each of the previous twelve months), less estimated future expenditures (based on current costs) to develop and produce the proved reserves, discounted at 10%, plus the cost of properties not being amortized and the lower of cost or estimated fair value of unproved properties included in the costs being amortized, net of income tax effects. We then conduct a “ceiling test” that compares the net book value of the full cost pool, after taxes, to the full cost ceiling limitation. In the event the full cost ceiling limitation is less than the full cost pool, we are required to record an impairment of our oil and natural gas properties.  

 

The ceiling test for each period presented was based on the following average spot prices, in each case adjusted for quality factors and regional differentials to derive estimated future net revenues. Prices presented in the table below are the trailing 12 month simple average spot prices at the first of the month for natural gas at Henry Hub (“HH”) and West Texas Intermediate (“WTI”) crude oil at Cushing, Oklahoma. The fluctuations demonstrate the volatility in oil and natural gas prices between each of the periods and have a significant impact on our ceiling test limitation.

 

 

 

 

 

 

 

 

 

 

 

Trailing 12 Month Simple Average Spot Prices

 

January 31, 2015

 

April 30, 2015

 

July 31, 2015

Oil (per Bbl)

$

91.22

 

$

78.58

 

$

67.65

Natural gas (per MMbtu)

$

4.20

 

$

3.69

 

$

3.23

Natural gas liquids (per Bbl)

$

50.07

 

$

41.96

 

$

34.98

 

We recognized impairments to our proved oil and natural gas properties of $206.0 million and $398.0 million for the three and six months ended July 31, 2015, respectively, primarily due to the decline in oil, natural gas and natural gas liquids prices. We did not recognize impairments to our proved oil and natural gas properties for the three and six months ended July 31, 2014. We will incur additional impairments to our oil and natural gas properties in future quarters if prices stay at current levels or decline further.  The amount of any future impairment is difficult to predict, and will depend, in part, upon future oil, natural gas and natural gas liquids prices to be utilized in the ceiling test, estimates of proved reserves and future capital expenditures and operating costs. The ceiling limitation is not intended to be indicative of the fair market value of our proved reserves or future results.  Impairment charges do not affect cash flow from operating activities but do adversely affect our net income and stockholders’ equity.  Any recorded impairment of oil and natural gas properties is not reversible at a later date.

 

The evaluation of impairment of our oil and natural gas properties includes estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revisions of such estimate. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered.

 

8


 

Oilfield Services Equipment and Other Property and Equipment.  Oilfield services equipment and other property and equipment consisted of the following as of:

 

 

 

 

 

 

 

 

(in thousands)

    

January 31, 2015

    

July 31, 2015

Land

 

$

7,888

 

$

7,888

Building and leasehold improvements

 

 

33,625

 

 

35,506

Oilfield service equipment

 

 

116,354

 

 

122,946

Vehicles

 

 

4,811

 

 

5,761

Software, computers and office equipment

 

 

5,327

 

 

6,481

Capital leases

 

 

853

 

 

853

Total depreciable assets

 

 

168,858

 

 

179,435

Accumulated depreciation

 

 

(35,189)

 

 

(54,121)

Depreciable assets, net

 

 

133,669

 

 

125,314

Assets not placed in service

 

 

1,247

 

 

3,508

Total oilfield service equipment and other property & equipment, net

 

$

134,916

 

$

128,822

 

Income Taxes.  The Company computes its quarterly tax provision using the effective tax rate method based on applying the anticipated annual effective rate to its year-to-date income or loss, except for discrete items. Income tax on discrete items is computed and recorded in the period in which the specific transaction occurs.

 

As noted above, the carrying value of our oil and natural gas properties exceeded the calculated value of the ceiling limitation resulting in an impairment of $398.0 million for the six months ended July 31, 2015. This impairment results in Triangle having three years of cumulative historical pre-tax losses and a net deferred tax asset position. Additionally, Triangle will likely be required to recognize additional impairments of its oil and natural gas properties in future periods if oil and natural gas prices remain at current levels or continue to decline and such impairments will likely be material. Triangle also had net operating loss carryovers (“NOLs”) for federal income tax purposes of $136.9 million at January 31, 2015. These losses and expected future losses were a key consideration that led Triangle to provide a valuation allowance against its net deferred tax assets as of April 30 and July 31, 2015 since it cannot conclude that it is more likely than not that its net deferred tax assets will be fully realized in future periods.

 

The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. At each reporting period, management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment. Future events or new evidence which may lead the Company to conclude that it is more likely than not that its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, sustained or continued improvements in oil prices, and taxable events that could result from one or more transactions. The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods.

 

In the first quarter of fiscal year 2016 the Company recorded the benefit of reversing its net deferred tax liability. As long as the Company concludes that it will continue to have a need for a valuation allowance against its net deferred tax assets, the Company likely will not have any additional income tax expense or benefit other than for federal alternative minimum tax expense, a release of a portion of the valuation allowance for net operating loss carryback claims or for state income taxes.

 

As of July 31, 2015, the Company had no unrecognized tax benefits. The Company’s management does not believe that there are any new items or changes in facts or judgments that should impact the Company’s position during the first six months of fiscal year 2016. Given the substantial net operating loss carryforwards at both the federal and state levels, neither significant interest expense nor penalties charged for any examining agents’ tax adjustments of income tax returns are anticipated, as any such adjustments would very likely only adjust net operating loss carryforwards.

 

Earnings per Share. Basic earnings per common share is computed by dividing net income (loss) attributable to the common stockholders by the weighted average number of common shares outstanding during the reporting period. Diluted net income per common share reflects increases in average shares outstanding from the potential dilution, under the treasury stock method, that could occur upon (i) exercise of stock options, (ii) vesting of restricted stock units, and (iii) conversion of convertible debt. The treasury stock method assumes exercise, vesting or conversion at the beginning of a period for securities outstanding at the end of a period. Also, the treasury stock method for calculating dilution assumes

9


 

that the increase in the number of shares is reduced by the number of shares which could have been repurchased by the Company at the quarter’s average stock price using assumed proceeds from (a) the exercise cost of the options and (b) the foregone future compensation expense of hypothetical early vesting of the outstanding restricted stock units. The assumed proceeds are adjusted for income tax effects. In the event of a net loss, no potential common shares are included in the calculation of shares outstanding, as their inclusion would be anti-dilutive.

 

The following table details the weighted average dilutive and anti-dilutive securities, which consist of options and unvested restricted stock, for the periods presented:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended

 

For the Six Months Ended

 

 

July 31,

 

July 31,

 

    

2014

    

2015

    

2014

 

2015

Dilutive

 

 

17,602,373

 

 

 —

 

 

17,447,130

 

 

 —

Anti-dilutive shares

 

 

4,500,000

 

 

10,888,828

 

 

4,500,000

 

 

10,888,828

 

The table below sets forth the computations of net income (loss) per common share (basic and diluted) for the periods presented:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended

 

For the Six Months Ended

 

 

July 31,

 

July 31,

(in thousands, except per share data)

    

2014

    

2015

    

2014

 

2015

Net income (loss) attributable to common stockholders

 

$

14,552

 

$

(193,346)

 

$

29,094

 

$

(373,545)

Effect of 5% convertible note conversion

 

 

996

 

 

 —

 

 

1,983

 

 

 —

Net income (loss) attributable to common stockholders after effect of 5% convertible note conversion

 

$

15,548

 

$

(193,346)

 

$

31,077

 

$

(373,545)

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic weighted average common shares outstanding

 

 

86,172

 

 

75,410

 

 

86,064

 

 

75,334

Effect of dilutive securities

 

 

17,602

 

 

 —

 

 

17,447

 

 

 —

Diluted weighted average common shares outstanding

 

 

103,774

 

 

75,410

 

 

103,511

 

 

75,334

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic net income (loss) per share

 

$

0.17

 

$

(2.56)

 

$

0.34

 

$

(4.96)

Diluted net income (loss) per share

 

$

0.15

 

$

(2.56)

 

$

0.30

 

$

(4.96)

 

Reclassifications.  Certain amounts in our unaudited condensed consolidated statement of operations for the three and six months ended July 31, 2014 have been reclassified to conform to the financial statement presentation for the periods ended July 31, 2015. The unaudited condensed consolidated statement of operations reclassifications relate to the break out of amortization of deferred loan costs from interest expense and amounts related to revisions in the Elmworth abandonment obligation that were reclassified from accretion of asset retirement obligations to depreciation and amortization expense. Such reclassifications had no impact on consolidated total assets, stockholders’ equity or net income previously reported.

 

10


 

3.  SEGMENT REPORTING

 

We conduct our operations within two reportable operating segments. We identified each segment based on management’s responsibility and the nature of their products, services, and costs. There are no major distinctions in geographical areas served as nearly all operations are in the Williston Basin of the United States. The Exploration and Production operating segment, consisting of TUSA and several insignificant oil and natural gas subsidiaries, is responsible for finding and producing oil and natural gas. The Oilfield Services segment, consisting of RockPile and its subsidiaries, is responsible for a variety of oilfield and complementary well completion services for both TUSA-operated wells and wells operated by third-parties. Corporate and Other includes our corporate office and several subsidiaries that management does not consider to be part of the Exploration and Production or Oilfield Services segments. Also included in Corporate and Other are our results from our investment in Caliber, including any changes in the fair value of our equity investment derivatives. 

 

Management evaluates the performance of our segments based upon net income (loss) before income taxes. The following tables present selected financial information for our operating segments for the three months ended July 31, 2015 and 2014.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended July 31, 2015

 

 

Exploration

 

 

 

 

Corporate

 

 

 

 

 

 

 

 

and

 

Oilfield

 

and

 

 

 

 

Consolidated

(in thousands)

 

Production

    

Services

    

Other

    

Eliminations

    

Total

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil, natural gas and natural gas liquids sales

 

$

55,263

 

$

 —

 

$

 —

 

$

 —

 

$

55,263

Oilfield services for third parties

 

 

 —

 

 

54,830

 

 

 —

 

 

(360)

 

 

54,470

Intersegment revenues

 

 

 —

 

 

14,601

 

 

 —

 

 

(14,601)

 

 

 —

Total revenues

 

 

55,263

 

 

69,431

 

 

 —

 

 

(14,961)

 

 

109,733

Expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating and production taxes

 

 

16,818

 

 

 —

 

 

 —

 

 

 —

 

 

16,818

Gathering, transportation and processing

 

 

6,641

 

 

 —

 

 

 —

 

 

 —

 

 

6,641

Depreciation and amortization

 

 

24,527

 

 

8,718

 

 

407

 

 

(1,408)

 

 

32,244

Impairment of oil and natural gas properties

 

 

206,000

 

 

 —

 

 

 —

 

 

 —

 

 

206,000

Accretion of asset retirement obligations

 

 

90

 

 

 —

 

 

 —

 

 

 —

 

 

90

Cost of oilfield services

 

 

 —

 

 

56,353

 

 

(1,238)

 

 

(8,396)

 

 

46,719

General and administrative, net of amounts capitalized:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Salaries and benefits

 

 

584

 

 

3,940

 

 

3,045

 

 

 —

 

 

7,569

Stock-based compensation

 

 

375

 

 

84

 

 

3,167

 

 

 —

 

 

3,626

Other general and administrative

 

 

349

 

 

1,034

 

 

2,011

 

 

 —

 

 

3,394

Total operating expenses

 

 

255,384

 

 

70,129

 

 

7,392

 

 

(9,804)

 

 

323,101

Income (loss) from operations

 

 

(200,121)

 

 

(698)

 

 

(7,392)

 

 

(5,157)

 

 

(213,368)

Other income (expense), net

 

 

18,290

 

 

(845)

 

 

3,116

 

 

(539)

 

 

20,022

Income (loss) before income taxes

 

$

(181,831)

 

$

(1,543)

 

$

(4,276)

 

$

(5,696)

 

$

(193,346)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

11


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended July 31, 2014

 

 

Exploration

 

 

 

 

Corporate

 

 

 

 

 

 

 

 

and

 

Oilfield

 

and

 

 

 

 

Consolidated

(in thousands)

    

Production

    

Services

    

Other

    

Eliminations

    

Total

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil, natural gas and natural gas liquids sales

 

$

80,506

 

$

 —

 

$

 —

 

$

 —

 

$

80,506

Oilfield services for third parties

 

 

 —

 

 

64,093

 

 

 —

 

 

(2,610)

 

 

61,483

Intersegment revenues

 

 

 —

 

 

37,962

 

 

 —

 

 

(37,962)

 

 

 —

Total revenues

 

 

80,506

 

 

102,055

 

 

 —

 

 

(40,572)

 

 

141,989

Expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating and production taxes

 

 

15,375

 

 

 —

 

 

 —

 

 

 —

 

 

15,375

Gathering, transportation and processing

 

 

3,733

 

 

 —

 

 

 —

 

 

 —

 

 

3,733

Depreciation and amortization

 

 

26,287

 

 

4,690

 

 

186

 

 

(4,456)

 

 

26,707

Accretion of asset retirement obligations

 

 

40

 

 

 —

 

 

 —

 

 

 —

 

 

40

Cost of oilfield services

 

 

 —

 

 

68,867

 

 

 —

 

 

(25,313)

 

 

43,554

General and administrative, net of amounts capitalized:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Salaries and benefits

 

 

1,560

 

 

2,922

 

 

2,051

 

 

 —

 

 

6,533

Stock-based compensation

 

 

343

 

 

127

 

 

1,337

 

 

 —

 

 

1,807

Other general and administrative

 

 

2,882

 

 

2,329

 

 

540

 

 

 —

 

 

5,751

Total operating expenses

 

 

50,220

 

 

78,935

 

 

4,114

 

 

(29,769)

 

 

103,500

Income (loss) from operations

 

 

30,286

 

 

23,120

 

 

(4,114)

 

 

(10,803)

 

 

38,489

Other income (expense), net

 

 

(4,267)

 

 

(667)

 

 

(7,752)

 

 

(912)

 

 

(13,598)

Net income (loss) before income taxes

 

$

26,019

 

$

22,453

 

$

(11,866)

 

$

(11,715)

 

$

24,891

 

The following tables present selected financial information for our operating segments for the six months ended July 31, 2015 and 2014.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Six Months Ended July 31, 2015

 

 

Exploration

 

 

 

 

Corporate

 

 

 

 

 

 

 

 

and

 

Oilfield

 

and

 

 

 

 

Consolidated

(in thousands)

    

Production

    

Services

    

Other

    

Eliminations

    

Total

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil, natural gas and natural gas liquids sales

 

$

103,041

 

$

 —

 

$

 —

 

$

 —

 

$

103,041

Oilfield services for third parties

 

 

 —

 

 

125,920

 

 

 —

 

 

(940)

 

 

124,980

Intersegment revenues

 

 

 —

 

 

24,105

 

 

 —

 

 

(24,105)

 

 

 —

Total revenues

 

 

103,041

 

 

150,025

 

 

 —

 

 

(25,045)

 

 

228,021

Expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating and production taxes

 

 

32,514

 

 

 —

 

 

 —

 

 

 —

 

 

32,514

Gathering, transportation and processing

 

 

12,989

 

 

 —

 

 

 —

 

 

 —

 

 

12,989

Depreciation and amortization

 

 

53,826

 

 

18,207

 

 

732

 

 

(2,715)

 

 

70,050

Impairment of oil and natural gas properties

 

 

398,000

 

 

 —

 

 

 —

 

 

 —

 

 

398,000

Accretion of asset retirement obligations

 

 

147

 

 

 —

 

 

 —

 

 

 —

 

 

147

Cost of oilfield services

 

 

 —

 

 

126,939

 

 

 —

 

 

(14,756)

 

 

112,183

General and administrative, net of amounts capitalized:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Salaries and benefits

 

 

925

 

 

8,769

 

 

6,298

 

 

 —

 

 

15,992

Stock-based compensation

 

 

696

 

 

135

 

 

5,303

 

 

 —

 

 

6,134

Other general and administrative

 

 

756

 

 

2,831

 

 

3,735

 

 

 —

 

 

7,322

Total operating expenses

 

 

499,853

 

 

156,881

 

 

16,068

 

 

(17,471)

 

 

655,331

Income (loss) from operations

 

 

(396,812)

 

 

(6,856)

 

 

(16,068)

 

 

(7,574)

 

 

(427,310)

Other income (expense), net

 

 

(2,712)

 

 

(1,720)

 

 

5,802

 

 

(1,046)

 

 

324

Income (loss) before income taxes

 

$

(399,524)

 

$

(8,576)

 

$

(10,266)

 

$

(8,620)

 

$

(426,986)

As of July 31, 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net oil and natural gas properties

 

$

871,169

 

$

 —

 

$

 —

 

$

(83,402)

 

$

787,767

Oilfield services equipment - net

 

$

 —

 

$

79,997

 

$

 —

 

$

 —

 

$

79,997

Other property and equipment - net

 

$

9,194

 

$

21,759

 

$

17,872

 

$

 —

 

$

48,825

Total assets

 

$

1,023,660

 

$

159,486

 

$

130,445

 

$

(103,634)

 

$

1,209,957

Total liabilities

 

$

770,143

 

$

130,685

 

$

151,669

 

$

(20,232)

 

$

1,032,265

12


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Six Months Ended July 31, 2014

 

 

Exploration

 

 

 

 

Corporate

 

 

 

 

 

 

 

 

and

 

Oilfield

 

and

 

 

 

 

Consolidated

(in thousands)

    

Production

    

Services

    

Other

    

Eliminations

    

Total

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil, natural gas and natural gas liquids sales

 

$

141,340

 

$

 —

 

$

 —

 

$

 —

 

$

141,340

Oilfield services for third parties

 

 

 —

 

 

103,650

 

 

 —

 

 

(3,219)

 

 

100,431

Intersegment revenues

 

 

 —

 

 

59,837

 

 

 —

 

 

(59,837)

 

 

 —

Total revenues

 

 

141,340

 

 

163,487

 

 

 —

 

 

(63,056)

 

 

241,771

Expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating and production taxes

 

 

26,449

 

 

 —

 

 

 —

 

 

 —

 

 

26,449

Gathering, transportation and processing

 

 

7,535

 

 

 —

 

 

 —

 

 

 —

 

 

7,535

Depreciation and amortization

 

 

46,440

 

 

8,280

 

 

362

 

 

(7,088)

 

 

47,994

Accretion of asset retirement obligations

 

 

65

 

 

 —

 

 

 —

 

 

 —

 

 

65

Cost of oilfield services

 

 

 —

 

 

112,578

 

 

 —

 

 

(41,314)

 

 

71,264

General and administrative, net of amounts capitalized:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Salaries and benefits

 

 

2,801

 

 

5,660

 

 

4,333

 

 

 —

 

 

12,794

Stock-based compensation

 

 

738

 

 

217

 

 

2,860

 

 

 —

 

 

3,815

Other general and administrative

 

 

4,419

 

 

4,688

 

 

1,776

 

 

 —

 

 

10,883

Total operating expenses

 

 

88,447

 

 

131,423

 

 

9,331

 

 

(48,402)

 

 

180,799

Income (loss) from operations

 

 

52,893

 

 

32,064

 

 

(9,331)

 

 

(14,654)

 

 

60,972

Other income (expense), net

 

 

(10,834)

 

 

(1,174)

 

 

1,746

 

 

(1,266)

 

 

(11,528)

Income (loss) before income taxes

 

$

42,059

 

$

30,890

 

$

(7,585)

 

$

(15,920)

 

$

49,444

 

Certain income statement reclassifications were made as previously noted, as well as changes to reflect the Exploration and Production depreciation and amortization expense gross rather than net of consolidating eliminations.

 

Eliminations and Other. For consolidation, intercompany revenues and expenses are eliminated with a corresponding reduction in Triangle’s capitalized well costs.

 

Under the full cost method of accounting, we defer recognition of oilfield services income (intersegment revenues less cost of oilfield services and related depreciation) for wells that we operate and this deferred income is credited to proved oil and natural gas properties. In addition, we eliminate our non-operating partners’ share of oilfield services income for well completion activities on properties we operate. We also defer Caliber gross profit from our share of its income associated with services it provided that were capitalized by TUSA, by charging such gross profit against income from equity investment and crediting proved oil and natural gas properties.

 

The above deferred income is indirectly recognized in future periods through a lower amortization rate as proved reserves are produced. For the three months ended July 31, 2015 and 2014, $0.1 and $2.9 million, respectively, of the depreciation and amortization elimination relates to the Exploration and Production segment and the balance relates to the Oilfield Services segment. For the six months ended July 31, 2015 and 2014, $0.6 and $4.3 million, respectively, of the depreciation and amortization elimination relates to the Exploration and Production segment and the balance relates to the Oilfield Services segment.

 

These differences, as well as differing amounts for impairments, result in basis differences between the net oil and gas property amounts presented in Triangle’s financial statements compared to those presented in TUSA’s standalone financial statements.

13


 

4.  LONG-TERM DEBT

 

The Company’s long-term debt consisted of the following as of January 31, 2015 and July 31, 2015:

 

 

 

 

 

 

 

 

 

 

(in thousands)

    

January 31, 2015

    

July 31, 2015

5% convertible note

 

$

135,877

 

$

139,295

TUSA credit facility due October 2018

 

 

119,272

 

 

172,272

RockPile credit facility due March 2019

 

 

104,887

 

 

86,920

TUSA 6.75% notes due July 2022

 

 

429,500

 

 

425,889

Other notes and mortgages payable

 

 

10,605

 

 

13,364

Total debt

 

 

800,141

 

 

837,740

Less current portion of debt:

 

 

 

 

 

 

Other notes and mortgages payable

 

 

(503)

 

 

(677)

Total long-term debt

 

$

799,638

 

$

837,063

 

Convertible Note. On July 31, 2012, the Company sold to NGP Triangle Holdings, LLC a 5% convertible note with an initial principal amount of $120.0 million (the Convertible Note) that became convertible after November 16, 2012 into the Company’s common stock at a conversion rate of one share per $8.00 of note principal.

 

The Convertible Note accrues interest at a rate of 5.0% per annum, compounded quarterly, on each December 31, March 31, June 30 and September 30, and on the date of any redemption, conversion or exchange of the Convertible Note. Such interest is paid-in-kind by adding to the principal balance of the Convertible Note, provided that, after September 30, 2017, the Company has the option to make such interest payments in cash. As of July 31, 2015, $19.3 million of accrued interest has been added to the principal balance of the Convertible Note.

 

TUSA Credit Facility. On April 11, 2013, TUSA entered into an Amended and Restated Credit Agreement, which was subsequently amended on various dates. On November 25, 2014, TUSA entered into a Second Amended and Restated Credit Agreement, which provides for a $1.0 billion senior secured revolving credit facility, with a sublimit for the issuance of letters of credit equal to $15.0 million. The TUSA credit facility has a maturity date of October 16, 2018.

 

On April 30, 2015, TUSA entered into Amendment No. 1 to its Second Amended and Restated Credit Agreement (Amendment No. 1) to, among other things, replace the existing total funded debt leverage ratio with a senior secured leverage ratio, add an interest coverage ratio, and add an equity cure right for non-compliance with financial covenants. The May 2015 semi-annual redetermination of the borrowing base was conducted concurrently with the execution of Amendment No. 1, and the borrowing base was adjusted from $435.0 million to $350.0 million.

 

Borrowings under the TUSA credit facility bear interest, at TUSA’s option, at either (i) the adjusted base rate (the highest of (A) the administrative agent’s prime rate, (B) the federal funds rate plus 0.50%, or (C) the one month Eurodollar rate (as defined in the agreement) plus 1.0%), plus an applicable margin that ranges between 0.50% and 1.50%, depending on TUSA’s utilization percentage of the then effective borrowing base, or (ii) the Eurodollar rate plus an applicable margin that ranges between 1.50% and 2.50%, depending on TUSA’s utilization percentage of the then effective borrowing base.

 

The lenders will redetermine the borrowing base under the TUSA credit facility on a semi-annual basis by May 1 and November 1. In addition, each of TUSA and the lenders may request an unscheduled borrowing base redetermination twice during each calendar year. If at any time the borrowing base is less than the amount of outstanding credit exposure under the TUSA credit facility, TUSA will be required to (i) prepay the principal amount of the loans in an amount sufficient to eliminate the excess, (ii) pledge additional collateral, (iii) prepay the excess in three equal monthly installments, or (iv) any combination of options (i) through (iii). TUSA will pay a commitment fee that ranges between 0.375% and 0.50% per annum on the unused availability under the TUSA credit facility. The TUSA credit facility is collateralized by certain of TUSA’s assets, including (1) at least 80% of the adjusted engineered value of TUSA’s oil and natural gas interests evaluated in determining the borrowing base for the facility, and (2) all of the personal property of TUSA and its subsidiaries. The obligations under the TUSA credit facility are guaranteed by TUSA’s subsidiaries, but Triangle is not a guarantor.

 

The TUSA credit facility contains various covenants and restrictive provisions that may, among other things, limit TUSA’s ability to sell assets, incur additional indebtedness, pay dividends, make investments or loans and create liens. In addition, the facility contains financial covenants requiring TUSA to maintain specified ratios of consolidated current

14


 

assets to consolidated current liabilities, consolidated senior secured debt to consolidated EBITDAX, and interest to consolidated EBITDAX. As of July 31, 2015, TUSA was in compliance with all covenants under the TUSA credit facility.

 

RockPile Credit Facility.  On March 25, 2014, RockPile entered into a Credit Agreement to provide a $100.0 million senior secured revolving credit facility. On November 13, 2014, RockPile entered into Amendment No. 1 to Credit Agreement and Incremental Commitment Agreement, which amended the credit facility to increase the borrowing capacity under the facility from $100.0 million to $150.0 million. The RockPile credit facility has a maturity date of March 25, 2019.

 

Borrowings under the RockPile credit facility bear interest, at RockPile’s option, at either (i) the alternative base rate (the highest of (a) the administrative agent’s prime rate, (b) the federal funds rate plus 0.5%, or (c) the one-month adjusted Eurodollar rate (as defined in the agreement) plus 1.0%), plus an applicable margin that ranges between 1.5% and 2.25%, depending on RockPile’s leverage ratio as of the last day of RockPile’s most recently completed fiscal quarter, or (ii) the Eurodollar rate plus an applicable margin that ranges between 2.50% and 3.25%, depending on RockPile’s leverage ratio as of the last day of RockPile’s most recently completed fiscal quarter.

 

RockPile pays a commitment fee that ranges between 0.375% and 0.50% per annum on the unused availability under the RockPile credit facility. RockPile also pays a per annum fee on all letters of credit issued under the RockPile credit facility, which will equal the applicable margin for loans accruing interest based on the Eurodollar rate and a fronting fee to the issuing lender equal to 0.125% of the letter of credit amount. The obligations under the RockPile credit facility are guaranteed by RockPile’s subsidiaries, but Triangle is not a guarantor.

 

The RockPile credit facility contains financial covenants requiring RockPile to maintain specified ratios of consolidated debt to EBITDA and Adjusted EBITDA to Fixed Charges. Amendment No. 1 also modified covenants in the RockPile credit facility related to certain restrictions on the payment of dividends and distributions and increased the amount of permitted capital expenditures. As of July 31, 2015, RockPile was in compliance with all financial covenants under the RockPile credit facility.

 

TUSA 6.75% Notes.  On July 18, 2014, TUSA entered into an Indenture (the Indenture) among TUSA, a TUSA wholly-owned subsidiary as guarantor, and Wells Fargo Bank, National Association, as trustee, governing the terms of TUSA’s $450.0 million aggregate principal amount of 6.75% Notes due 2022 (the TUSA 6.75% Notes).

 

The TUSA 6.75% Notes were issued in a private offering exempt from the registration requirements of the Securities Act of 1933, as amended (the Securities Act), to qualified institutional buyers in accordance with Rule 144A and to persons outside of the United States pursuant to Regulation S under the Securities Act. The TUSA 6.75% Notes are senior unsecured obligations of TUSA and are guaranteed on a senior unsecured basis by the initial guarantor and another TUSA wholly-owned subsidiary that became a guarantor of the TUSA 6.75% Notes in early December 2014. The TUSA 6.75% Notes have not been registered under the Securities Act and may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements.

 

The TUSA 6.75% Notes bear interest at a rate of 6.75% per year, accruing from July 18, 2014. Interest on the TUSA 6.75% Notes is payable semiannually in arrears on January 15 and July 15 of each year, beginning on January 15, 2015. The TUSA 6.75% Notes will mature on July 15, 2022, subject to earlier repurchase or redemption in accordance with the terms of the Indenture. The Company incurred $10.5 million of offering costs which have been deferred and are being recognized on the effective interest method over the life of the notes.

 

TUSA may redeem some or all of the TUSA 6.75% Notes at any time prior to July 15, 2017 at a price equal to 100% of the principal amount of the notes redeemed plus accrued and unpaid interest, if any, to the redemption date and a make-whole premium set forth in the Indenture. On or after July 15, 2017, TUSA may redeem some or all of the TUSA 6.75% Notes at any time at a price equal to 105% of the principal amount of the notes redeemed (103% after July 15, 2018, 102% after July 15, 2019 and 100% after July 15, 2020), plus accrued and unpaid interest, if any, to the redemption date. In addition, at any time prior to July 15, 2017, TUSA may redeem up to 35% of the aggregate principal amount of the TUSA 6.75% Notes at a specified redemption price set forth in the Indenture plus accrued and unpaid interest, if any, to the redemption date, with the net cash proceeds of certain equity offerings. If TUSA experiences certain change of control events, TUSA must offer to repurchase the TUSA 6.75% Notes at 101% of their principal amount, plus accrued and unpaid interest, if any, to the redemption date.

 

15


 

The Indenture permits TUSA to purchase TUSA 6.75% Notes in the open market. In fiscal year 2015, TUSA repurchased TUSA 6.75% Notes with a face value of $20.5 million for $13.9 million, immediately retired the repurchased notes, and recognized a gain on extinguishment of debt of $6.6 million.  During the three months ended July 31, 2015, TUSA repurchased additional TUSA 6.75% Notes with a face value of $3.6 million for $2.5 million, immediately retired the repurchased notes, and recognized a gain on extinguishment of debt of $1.1 million.

 

The Indenture contains covenants that, among other things, restrict TUSA’s ability and the ability of any guarantor subsidiary to sell certain assets; make certain dividends, distributions, investments and other restricted payments; incur certain additional indebtedness and issue preferred stock; create certain liens; enter into transactions with affiliates; designate subsidiaries as unrestricted subsidiaries, and consolidate, merge or sell substantially all of TUSA’s assets. These covenants are subject to a number of important exceptions and qualifications. As of July 31, 2015, TUSA was in compliance with all covenants under the TUSA 6.75% Notes.

 

5.  HEDGING AND COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS

 

Through TUSA, the Company has entered into commodity derivative instruments utilizing costless collars and swaps to reduce the effect of price changes on a portion of our future oil production. A collar requires us to pay the counterparty if the settlement price is above the ceiling price, and requires the counterparty to pay us if the settlement price is below the floor price. The objective of the Company’s use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and natural gas prices and to manage its exposure to commodity price risk. While the use of these derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company’s ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure or reduce existing derivative contracts, or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes.

 

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are currently with four counterparties. The Company has netting arrangements with each counterparty that provide for the offset of payables against receivables from separate derivative arrangements with the same underlier with the counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.

 

The Company’s commodity derivative instruments are measured at fair value. The Company has not designated any of its derivative contracts as fair value or cash flow hedges. Therefore, the Company does not apply hedge accounting to its commodity derivative instruments. Net gains and losses on derivative activities are recorded based on the changes in the fair values of the derivative instruments. Net gains and losses on derivative activities are recorded in the commodity derivatives gains (losses) caption on the consolidated statements of operations. The Company’s cash flows are only impacted when the actual settlements under the commodity derivative contracts result in a payment to or from the counterparty. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s consolidated statements of cash flows. 

 

The components of commodity derivative gains (losses) in the consolidated statements of operations are as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended

 

For the Six Months Ended

 

 

July 31,

 

July 31,

(in thousands)

 

2014

 

2015

 

2014

 

2015

Realized commodity derivative gains (losses)

 

$

(2,954)

 

$

17,016

 

$

(3,772)

 

$

36,484

Unrealized commodity derivative gains (losses)

 

 

2,033

 

 

8,033

 

 

(2,605)

 

 

(25,409)

Commodity derivative gains (losses), net

 

$

(921)

 

$

25,049

 

$

(6,377)

 

$

11,075

 

16


 

The Company’s commodity derivative contracts as of July 31, 2015 are summarized below:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Contract

 

 

 

Quantity

 

Weighted Average

 

Weighted Average

 

Weighted Average

 

    

Type

    

Basis (1)

    

(Bbl/d)

 

Put Strike

 

Call Strike

  

Price

August 1, 2015 to January 31, 2016

 

Collar

 

NYMEX

 

2,739

 

$

85.45

 

$

98.20

 

 

 

August 1, 2015 to January 31, 2016

 

Swap

 

NYMEX

 

1,755

 

 

 

 

 

 

 

$

60.22

February 1, 2016 to January 31, 2017

 

Swap

 

NYMEX

 

2,746

 

 

 

 

 

 

 

$

60.23

(1)

NYMEX refers to West Texas Intermediate crude oil prices at Cushing, Oklahoma as quoted on the New York Mercantile Exchange.

 

In August 2015, the Company unwound certain commodity derivative swap contracts and realized a gain of $9.3 million.  The early settled contracts were for 2,000 barrels of oil per day at an average fixed price of $60.34 for the period from January 1, 2016 to December 31, 2016.

 

The estimated fair values of commodity derivatives included in the consolidated balance sheets at January 31, 2015 and July 31, 2015 are summarized below. The Company does not offset asset and liability positions with the same counterparties within the consolidated financial statements; rather, all contracts are presented at their gross estimated fair value. As of the dates indicated, the Company’s derivative assets and liabilities are presented below (in thousands). These balances represent the estimated fair value of the contracts. The Company has not designated any of its derivative contracts as cash-flow hedging instruments for accounting purposes. The main headings represent the balance sheet captions for the contracts presented.

 

 

 

 

 

 

 

 

(in thousands)

 

January 31, 2015

 

July 31, 2015

Current Assets:

 

 

 

 

 

 

Crude oil derivative contracts

 

$

54,775

 

$

26,677

 

 

 

 

 

 

 

Other Long-Term Assets:

 

 

 

 

 

 

Crude oil derivative contracts

 

 

 —

 

 

2,689

 

 

 

 

 

 

 

Total derivative asset

 

$

54,775

 

$

29,366

 

 

6.  ACQUISITIONS

 

In June 2014, we acquired from Marathon Oil Company (Marathon) certain oil and natural gas leaseholds and related producing properties located in Williams County, North Dakota, Sheridan County, Montana, and Roosevelt County, Montana comprising approximately 41,100 net acres and various other related rights, permits, contracts, equipment and other assets for approximately $90.4 million in cash, net of certain closing adjustments of $9.6 million.

 

The acquisition was accounted for using the acquisition method under ASC-805, Business Combinations, which requires the assets acquired and liabilities assumed to be recorded at fair value as of the acquisition date of June 30, 2014.

 

The following unaudited pro forma financial information represents the combined results for the Company and the properties acquired from Marathon, in June of 2014, as if the acquisitions had occurred on February 1, 2014.

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended

 

For the Six Months Ended

(in thousands, except per share data)

    

July 31, 2014

    

July 31, 2014

Operating revenues

 

$

146,559

 

$

253,206

Net income (loss)

 

$

15,427

 

$

31,341

 

 

 

 

 

 

 

Earnings (loss) per common share

 

 

 

 

 

 

Basic

 

$

0.18

 

$

0.36

Diluted

 

$

0.16

 

$

0.32

 

 

 

 

 

 

 

Weighted average common shares outstanding:

 

 

 

 

 

 

Basic

 

 

86,172

 

 

86,064

Diluted

 

 

103,774

 

 

103,511

 

17


 

The pro forma information includes the effects of adjustments for depreciation and amortization expense of $1.3 million and $3.3 million, respectively, for the three and six month periods ended July 31, 2014. The pro forma results do not include any cost savings that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the transactions had been completed as of the beginning of the period, nor are they necessarily indicative of future results.

 

7.  EQUITY INVESTMENT AND EQUITY INVESTMENT DERIVATIVES

 

Equity Investment. On October 1, 2012, Triangle Caliber Holdings, LLC (“Triangle Caliber Holdings”), a wholly-owned subsidiary of Triangle, entered into a joint venture with FREIF Caliber Holdings LLC (“FREIF”), a wholly-owned subsidiary of First Reserve Energy Infrastructure Fund. The joint venture entity, Caliber, was formed to provide crude oil, natural gas and water transportation and related services to the Company and third parties primarily within the Williston Basin of North Dakota and Montana.

 

On January 31, 2015, Triangle Caliber Holdings entered into a series of agreements modifying its joint venture with FREIF. In connection with the modifications, Triangle Caliber Holdings entered into a Second Amended and Restated Contribution Agreement, dated January 31, 2015 (the “2nd A&R Contribution Agreement”), with FREIF and the general partner of Caliber, which is owned and controlled equally between Triangle Caliber Holdings and FREIF. Pursuant to the terms of the 2nd A&R Contribution Agreement, FREIF agreed to contribute an additional $34.0 million to Caliber in exchange for 2,720,000 Class A Units. FREIF funded the $34.0 million contribution, and the additional 2,720,000 Class A Units were issued, on February 2, 2015. Triangle made no capital contribution to Caliber in connection with the 2nd A&R Contribution Agreement or the issuance of the 2,720,000 Class A Units. Following the issuance, FREIF holds 17,720,000 Class A Units, representing an approximate 71.7% Class A Units ownership interest in Caliber, and Triangle Caliber Holdings holds 7,000,000 Class A Units, representing an approximate 28.3% Class A Units ownership interest in Caliber. Triangle recognized a gain in the first six months of fiscal year 2016 of $2.9 million related to Caliber’s issuance of these 2,720,000 Class A Units to FREIF.

 

Also pursuant to the terms of the 2nd A&R Contribution Agreement, Triangle Caliber Holdings received warrants for the purchase of an additional 3,626,667 Class A Units, and FREIF received warrants (Series 5) for the purchase of an additional 906,667 Class A Units.  The warrants received by Triangle Caliber Holdings on February 2, 2015 included 2,357,334 Class A (Series 1 through 4) Warrants at strike prices and expiration dates noted below and 1,269,333 Class A (Series 6) Warrants with a strike price of $12.50 and an expiration date of February 2, 2018.

 

The following summarizes the Company’s equity investment holdings in Caliber as of January 31, 2015 and July 31, 2015 and the strike prices for exercising warrants as of July 31, 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Expiration

 

Strike Price at

 

As of

 

As of

 

 

Date

 

July 31, 2015

 

January 31, 2015

 

July 31, 2015

Class A Units

 

 

 —

 

$

 —

 

7,000,000

 

7,000,000

Series 1 Warrants

 

 

October 1, 2024

 

$

12.78

 

5,600,000

 

6,615,467

Series 2 Warrants

 

 

October 1, 2024

 

$

22.09

 

2,400,000

 

2,835,200

Series 3 Warrants

 

 

September 12, 2025

 

$

22.09

 

3,000,000

 

3,544,000

Series 4 Warrants

 

 

September 12, 2025

 

$

28.09

 

2,000,000

 

2,362,667

Series 6 Warrants

 

 

February 2, 2018

 

$

12.50

 

 —

 

1,269,333

 

18


 

The following summarizes the activities related to the Company’s equity investment in Caliber for the six months ended July 31, 2015:

 

 

 

 

 

 

 

For the Six Months Ended

(in thousands)

 

July 31, 2015

Balance at January 31, 2015

 

$

64,411

 

 

 

 

Capital contributions

 

 

 —

Distributions

 

 

 —

Equity investment share of net income before intra-company profit eliminations

 

 

1,902

Change in fair value of warrants

 

 

4,516

Gain on Caliber capital transactions

 

 

2,880

 

 

 

 

Balance at July 31, 2015

 

$

73,709

 

 

 

 

Fair value of warrants at July 31, 2015

 

$

5,020

 

Equity Investment Derivatives.  At January 31, 2015 and July 31, 2015, the Company held Class A (Series 1 through Series 4 and Series 6) Warrants to acquire additional ownership in Caliber. These instruments are considered to be equity investment derivatives and are valued at each reporting period using valuation techniques for which the inputs are generally less observable than from objective sources.

 

8.  CAPITAL STOCK

 

The Company had 106.7 million shares of common stock issued or reserved for issuance at July 31, 2015. At July 31, 2015, the Company had 75.5 million shares of common stock issued and outstanding. The Company also had 1.8 million shares of common stock reserved for issuance pursuant to outstanding awards under its 2011 Omnibus Incentive Plan and 3.1 million shares of common stock reserved for issuance pursuant to outstanding awards under its 2014 Equity Incentive Plan (the 2014 Plan). The Company also had 2.9 million shares of common stock reserved that remained available for issuance under the 2014 Plan, as well as 6.0 million shares of common stock reserved for issuance under the CEO Stand-Alone Stock Option Agreement. Lastly, the Company had 17.4 million shares of common stock reserved for issuance pursuant to the Convertible Note at July 31, 2015.

 

The Company’s Board of Directors (the Board) approved a program authorizing the repurchase of outstanding shares of the Company’s common stock in amounts equal to the aggregate of (i) $25.0 million of the Company’s common stock (Tranche 1), (ii) up to the number of shares of common stock authorized for issuance under the Company’s 2014 Equity Incentive Plan and its CEO Stand-Alone Stock Option Agreement (Tranche 2), and (iii) up to the number of shares of common stock potentially issuable, at any given time, pursuant to the paid-in-kind interest accrued on the Convertible Note (Tranche 3). The program stipulates that shares of common stock may be repurchased from time to time, in amounts and at prices that the Company deems appropriate, subject to market and business conditions and other considerations. The repurchase program has no expiration date and may be suspended or discontinued at any time without prior notice. There were no common stock repurchases for the three and six months ended July 31, 2015. As of July 31, 2015, the number of shares of common stock remaining available for repurchase under the Board approved program was 5,374,890 shares.

 

9.  SHARE-BASED COMPENSATION

 

The Company has granted equity awards to officers, directors, and certain employees of the Company including restricted stock units and stock options. In addition, RockPile has granted Series B Units which represent interests in future RockPile profits. The Company measures its awards based on the award’s grant date fair value which is recognized ratably over the applicable vesting period.

 

On May 27, 2014, the Board approved the 2014 Plan, which was approved by the Company’s stockholders on July 17, 2014. No additional awards may be granted under prior plans but all outstanding awards under prior plans shall continue in accordance with their applicable terms and conditions. The 2014 Plan authorizes the Company to issue stock options, SARs, restricted stock, restricted stock units, cash awards, and other awards to any employees, officers, directors, and

19


 

consultants of the Company and its subsidiaries. The maximum number of shares of common stock issuable under the 2014 Plan is 6.0 million shares, subject to adjustment for certain transactions.

 

For the three and six months ended July 31, 2014 and 2015, the Company recorded share-based compensation related to restricted stock units, stock options and RockPile Series B Units as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended

 

For the Six Months Ended

 

 

July 31,

 

July 31,

(in thousands)

    

2014

    

2015

    

2014

 

2015

Restricted stock units

 

$

1,503

 

$

2,584

 

$

3,274

 

$

4,663

Stock options

 

 

487

 

 

1,347

 

 

973

 

 

2,045

RockPile Series B Units

 

 

127

 

 

84

 

 

217

 

 

135

 

 

 

2,117

 

 

4,015

 

 

4,464

 

 

6,843

Less amounts capitalized to oil and natural gas properties

 

 

(310)

 

 

(389)

 

 

(649)

 

 

(709)

Compensation expense

 

$

1,807

 

$

3,626

 

$

3,815

 

$

6,134

 

Restricted Stock Units. During the six months ended July 31, 2015, the Company granted 1,773,343 restricted stock units as compensation to employees, officers, and directors which generally vest over one to five years. As of July 31, 2015, there was approximately $23.2 million of total unrecognized compensation expense related to unvested restricted stock units. This compensation expense is expected to be recognized over the remaining vesting period of the related awards of approximately 3.3 years on a weighted average basis. When restricted stock units vest, the holder has the right to receive one share of the Company’s common stock per vesting unit.

 

The following table summarizes the activity for our restricted stock units during the six months ended July 31, 2015:  

 

 

 

 

 

 

 

 

 

 

 

Weighted

 

 

 

 

Average

 

 

Number of

 

Award Date

 

    

Shares

    

Fair Value

Restricted stock units outstanding - January 31, 2015

 

2,914,045

 

$

7.92

Units granted

 

1,773,343

 

$

4.93

Units forfeited

 

(63,588)

 

$

8.62

Units vested

 

(434,971)

 

$

7.79

Restricted stock units outstanding - July 31, 2015

 

4,188,829

 

$

6.66

 

Stock Options. There were no grants, exercises or forfeitures of stock options during the six months ended July 31, 2015. The following table summarizes the stock options outstanding at July 31, 2015:  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Remaining

 

 

 

 

 

 

Exercise Price

 

Contractual Life

 

Number of Shares

per Share

    

(years)

    

Outstanding

    

Exercisable

$

7.50

 

7.93

 

 

750,000

 

 

150,000

$

8.50

 

7.93

 

 

750,000

 

 

150,000

$

10.00

 

7.93

 

 

1,500,000

 

 

300,000

$

12.00

 

7.93

 

 

1,500,000

 

 

300,000

$

15.00

 

7.93

 

 

1,500,000

 

 

300,000

$

12.00

 

6.12

 

 

233,333

 

 

 —

$

14.00

 

6.12

 

 

233,333

 

 

 —

$

16.00

 

9.12

 

 

233,334

 

 

 —

 

 

 

 

 

 

6,700,000

 

 

1,200,000

 

 

 

 

 

 

 

 

 

 

Weighted average exercise price per share

$

11.54

 

$

11.25

 

 

 

 

 

 

 

 

 

 

Weighted average remaining contractual life

 

7.85

 

 

7.93

 

As of July 31, 2015, there was approximately $16.5 million of total unrecognized compensation expense related to stock options. This compensation expense is expected to be recognized over the remaining vesting period of the related awards of approximately 2.8 years.

20


 

 

RockPile Share-Based Compensation. RockPile currently has two classes of equity; Series A Units, which are voting units with an 8% preference, and Series B Units, which are non-voting equity awards. RockPile approved a plan that includes provisions allowing RockPile to make equity grants in the form of restricted units (Series B Units) pursuant to Restricted Unit Agreements. The plan authorizes RockPile to issue an aggregate of up to 6.0 million Series B Units in multiple series designated by a sequential number with the right to reissue forfeited or redeemed Series B Units.

 

The following table summarizes the activity for RockPile’s Series B Units for the six months ended July 31, 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Series

 

Series

 

Series

 

Series

 

 

 

    

B-1 units

    

B-2 units

    

B-3 units

    

B-4 units

    

Total

Units outstanding - January 31, 2015

 

2,920,000

 

60,000

 

910,000

 

1,412,000

 

5,302,000

Units redeemed

 

 —

 

 —

 

 —

 

 —

 

 —

Units granted

 

 —

 

 —

 

 —

 

 —

 

 —

Units forfeited

 

 —

 

 —

 

(96,000)

 

(74,000)

 

(170,000)

Units outstanding - July 31, 2015

 

2,920,000

 

60,000

 

814,000

 

1,338,000

 

5,132,000

Vested

 

2,920,000

 

30,000

 

352,000

 

117,600

 

3,419,600

Unvested

 

 —

 

30,000

 

462,000

 

1,220,400

 

1,712,400

 

Series B Units currently have a 1 to 46 month vesting schedule. Compensation costs are determined using a Black-Scholes option pricing model based upon the grant date calculated fair market value of the award and is recognized ratably over the applicable vesting period. As of July 31, 2015, there was approximately $2.3 million of unrecognized compensation expense related to unvested Series B Units. We expect to recognize such expense on a pro-rata basis on the Series B Units’ remaining vesting schedule.

 

10.  FAIR VALUE MEASUREMENTS

 

The FASB’s ASC 820, Fair Value Measurement and Disclosure, establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

 

·

Level 1: Quoted prices are available in active markets for identical assets or liabilities;

·

Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability; and

·

Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flows models or valuations.

 

The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

 

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of January 31, 2015 and July 31, 2015, by level within the fair value hierarchy:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of January 31, 2015

(in thousands)

    

Level 1

    

Level 2

    

Level 3

    

Total

Assets:

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivative assets

 

$

 —

 

$

54,775

 

$

 —

 

$

54,775

Equity investment derivative assets

 

$

 —

 

$

 —

 

$

504

 

$

504

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

RockPile earn-out liability

 

$

 —

 

$

(1,825)

 

$

 —

 

$

(1,825)

21


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of July 31, 2015

(in thousands)

    

Level 1

    

Level 2

    

Level 3

    

Total

Assets:

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivative assets

 

$

 —

 

$

29,366

 

$

 —

 

$

29,366

Equity investment derivative assets

 

$

 —

 

$

 —

 

$

5,020

 

$

5,020

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

RockPile earn-out liability

 

$

 —

 

$

(1,242)

 

$

 —

 

$

(1,242)

 

Commodity Derivative Instruments. The Company determines its estimate of the fair value of commodity derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third-parties, the credit rating of each counterparty, and the Company’s own credit rating. In considering counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments. The Company believes that each of its counterparties is creditworthy and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. At July 31, 2015, commodity derivative instruments utilized by the Company consist of costless collars and swaps. The Company’s commodity derivative instruments are valued using public indices and are traded with third-party counterparties, but are not openly traded on an exchange. As such, the Company has classified these commodity derivative instruments as Level 2.

 

Caliber Class A (Series 1 through Series 4 and Series 6) Warrants. The Company determines its estimate of the fair value of Caliber Class A Warrants using a Monte Carlo Simulation (“MCS”) model. For each MCS, the value of the Class A Units was forecasted at the end of each quarter based on a predetermined yield, and the strike price for the warrant is adjusted accordingly. At July 31, 2015, the fair value of the underlying Class A Units was estimated employing an income approach using a MCS model and discounted cash flows, and a market approach based on observed valuation multiples for comparable public companies.  Key inputs into these valuation approaches are generally less observable than those from objective sources. Therefore, the Company has classified these instruments as Level 3.

 

Earn-out Liability. The Company determined the estimated fair value of the earn-out liability relating to RockPile’s acquisition of Team Well Service, Inc. using a market approach based on information derived from an analysis performed for RockPile by an independent third-party. This analysis used publicly available information from market participants in the same industry, generally accepted methods for estimating an investor’s return requirements, and quoted market prices in active markets. As such, the earn-out liability has been classified as Level 2.

 

Fair Value of Financial Instruments.  The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable and payable, derivatives and Caliber Class A Warrants (discussed above), and long-term debt. The carrying values of cash equivalents and accounts receivable and payable are representative of their fair values due to their short-term maturities. The Convertible Note’s estimated fair value is based on discounted cash flows analysis and option pricing. The carrying amount of the Company’s revolving credit facilities approximated fair value because the interest rate of the facilities is variable. The fair values of the other notes and mortgages payable is not significantly different than their carrying values. The fair value of the TUSA 6.75% Notes is derived from quoted market prices. This disclosure does not impact our financial position, results of operations or cash flows.

 

The carrying values and fair values of the Company’s debt instruments are as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

January 31, 2015

 

July 31, 2015

 

 

Carrying

 

Estimated

 

Carrying

 

Estimated

(in thousands)

    

Value

    

Fair Value

    

Value

    

Fair Value

5% convertible note

 

$

135,877

 

$

137,790

 

$

139,295

 

$

136,361

Revolving credit facilities

 

 

224,159

 

 

224,159

 

 

259,192

 

 

259,192

TUSA 6.75% notes

 

 

429,500

 

 

303,871

 

 

425,889

 

 

317,293

Other notes and mortgages payable

 

 

10,605

 

 

10,605

 

 

13,364

 

 

13,364

 

 

22


 

11.  RELATED PARTY TRANSACTIONS

 

TUSA and an affiliate of Caliber have entered into certain midstream services agreements for (i) crude oil gathering, stabilization, treating and redelivery; (ii) natural gas compression, gathering, dehydration, processing and redelivery; (iii) produced water transportation and disposal services; and (iv) fresh water transportation for TUSA’s oil and natural gas drilling and production operations. The agreements also include an acreage dedication from TUSA and a firm volume commitment by the Caliber affiliate for each service line. TUSA has agreed to deliver minimum monthly revenues derived from the fees paid by TUSA to the Caliber affiliate for volumes of oil, natural gas, produced water, and fresh water for a primary term of 15 years beginning in 2014. The aggregate minimum revenue commitment over the term of the agreements is $405.0 million, of which $336.3 million was outstanding at July 31, 2015.

 

TUSA and an affiliate of Caliber have also entered into a gathering services agreement, pursuant to which the Caliber affiliate will provide certain gathering-related measurement services to TUSA, and a fresh water sales agreement that will make available certain volumes of fresh water for purchase by TUSA at a set per barrel fee for a primary term of five years from the in-service date anticipated to be in the first half of fiscal year 2016. The fresh water sales agreement obligates TUSA to purchase all of the fresh water it requires for its drilling and operating activities exclusively from the Caliber affiliate, subject to availability, but it does not require TUSA to purchase a minimum volume of fresh water.

 

During the six months ended July 31, 2015, TUSA sold one salt water disposal well to an affiliate of Caliber for net proceeds of $6.0 million.

 

12.  SUPPLEMENTAL DISCLOSURES OF CASH FLOWS INFORMATION

 

 

 

 

 

 

 

 

 

 

For the Six Months Ended July 31,

(in thousands)

    

2014

    

2015

Cash paid during the period for:

 

 

 

 

 

 

Interest expense

 

$

4,717

 

$

16,078

Income taxes

 

$

550

 

$

 —

 

 

 

 

 

 

 

Non-cash investing activities:

 

 

 

 

 

 

Additions to oil and natural gas properties through:

 

 

 

 

 

 

Increase (decrease) in accounts payable and accrued liabilities

 

$

37,151

 

$

(15,770)

Capitalized stock based compensation

 

$

649

 

$

709

Change in asset retirement obligations

 

$

1,106

 

$

425

 

 

 

 

 

 

 

Non-cash financing activities:

 

 

 

 

 

 

Notes payable issued for redemption of RockPile Series B Units

 

$

1,041

 

$

 —

 

 

 

 

 

23


 

ITEM 2.  MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

Overview

 

We are an independent energy holding company with three principal lines of business: oil and natural gas exploration, development and production; oilfield services; and midstream services. We conduct these activities primarily in the Williston Basin of North Dakota and Montana through TUSA and RockPile, the Company’s two principal wholly-owned subsidiaries, and Caliber, our joint venture with FREIF.

 

Summary of results for the six months ended July 31, 2015

 

·

Average daily production volumes were 13,646 Boe/day for the six months ended July 31, 2015, compared to 9,359 Boe/day for the six months ended July 31, 2014, an increase of 46%. 

·

TUSA spud 16 gross (13.0 net) operated wells and completed 14 gross (9.9 net) operated wells during the six months ended July 31, 2015. As of July 31, 2015, TUSA had 18 gross (16.4 net) operated wells that have been drilled and were pending completion.

·

Lower average realized prices of $41.72 per Boe for the six months ended July 31, 2015, versus $83.42 per Boe for the six months ended July 31, 2014, resulted in oil, natural gas and natural gas liquids sales for the six months ended July 31, 2015 of $103.0 million compared to $141.3 million for the six months ended July 31, 2014.

·

RockPile completed 14 TUSA wells and 89 third-party wells in the six months ended July 31, 2015, as compared to 24 TUSA wells and 36 third-party wells in the six months ended July 31, 2014.

·

Oilfield services revenue for the six months ended July 31, 2015 was $125.0 million compared to $100.4 million for the six months ended July 31, 2014.  

·

The competitive oilfield services pricing environment resulted in a negative gross profit of $3.3 million for the six months ended July 31, 2015 compared to a gross profit of $23.7 million for the six months ended July 31, 2014 after eliminations of intercompany gross profit.

·

The carrying value of our oil and natural gas properties exceeded the calculated value of the ceiling limitation  at  July 31, 2015, resulting in an impairment of $398.0 million for the six months ended July 31, 2015.

·

Cash flows provided by operating activities were $80.0 million for the six months ended July 31, 2015 compared to $61.8 million for the six months ended July 31, 2014.

·

TUSA amended its credit facility to revise its financial covenants and add an equity cure right.

 

Drilling and Completions

 

The following tables summarize our wells spud and completed during the three and six months ended July 31, 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended

 

For the Six Months Ended

 

 

July 31, 2015

 

July 31, 2015

 

 

Spud

 

Completed

 

Spud

 

Completed

 

    

Gross

    

Net

    

Gross

    

Net

  

Gross

    

Net

    

Gross

    

Net

Operated wells

 

5

 

4.1

 

9

 

6.6

 

16

 

13.0

 

14

 

9.9

Non-operated wells

 

2

 

0.1

 

5

 

0.2

 

4

 

0.1

 

27

 

0.8

 

 

7

 

4.2

 

14

 

6.8

 

20

 

13.1

 

41

 

10.7

 

Properties, Plan of Operations and Capital Expenditures

 

We own operated and non-operated leasehold positions in the Williston Basin of North Dakota and Montana. As of July 31, 2015, we have completed a total of 110 gross (79.4 net) operated wells in the Williston Basin and have an interest in approximately 474 gross (26.3 net) non-operated wells.

 

As of July 31, 2015, we were running one drilling rig, which we released in August 2015. We plan to periodically reassess the appropriate number of rigs for our future drilling program based on a variety of factors including, but not limited to, prevailing oil and natural gas prices and operational efficiencies.

 

24


 

Our oil and natural gas property expenditures during the six months ended July 31, 2014 and 2015 are summarized below:

 

 

 

 

 

 

 

 

 

 

For the Six Months Ended

 

 

July 31,

(in thousands)

    

2014

 

2015

Costs incurred during the period

 

 

 

 

 

 

Acquisition of properties:

 

 

 

 

 

 

Proved

 

$

91,067

 

$

243

Unproved

 

 

40,301

 

 

 —

Exploration

 

 

52,338

 

 

49,499

Development

 

 

133,186

 

 

68,405

Oil and natural gas expenditures

 

 

316,892

 

 

118,147

Asset retirement obligations, net

 

 

1,106

 

 

425

 

 

$

317,998

 

$

118,572

 

For the three and six months ended July 31, 2015, we recorded impairments to our oil and natural gas properties of $206.0 million and $398.0 million, respectively, primarily due to the significant decline in oil, natural gas and natural gas liquids prices. The trailing twelve month reference prices at July 31, 2015 were $67.65 per Bbl of oil, $3.23 per MMbtu for natural gas and $34.98 per Bbl of natural gas liquids. For the three and six months ended July 31, 2014, we did not record an impairment to our oil and natural gas properties.

 

Because the ceiling calculation requires rolling 12-month average commodity prices, the effect of lower quarter-over-quarter prices in fiscal year 2016 compared to fiscal year 2015 will be a lower ceiling limitation each quarter.  We will incur additional impairments to our oil and natural gas properties in future quarters if prices stay at current levels or decline further.  The amount of any future impairment is difficult to predict and will depend, in part, upon future oil, natural gas and natural gas liquids prices to be utilized in the ceiling test, estimates of proved reserves and future capital expenditures and operating costs.

 

If the simple average of oil, natural gas and natural gas liquids prices as of the first day of each month for the trailing 12-month period ended July 31, 2015 had been $58.58 per Bbl of oil, $2.98 per MMbtu for natural gas and $29.44 per Bbl of natural gas liquids and all other factors remained constant, our impairment for the six months ended July 31, 2015 would have increased, on a pro forma basis, by approximately $180 million. The aforementioned prices were calculated based on a 12-month simple average, which includes the oil and natural gas prices on the first day of the month for the ten months ended August 31, 2015 and the prices for August 2015 were held constant for the remaining two months.

 

This calculation of the impact of lower commodity prices is prepared based on the presumption that all other inputs and assumptions are held constant with the exception of oil, natural gas and natural gas liquids prices. Therefore, this calculation strictly isolates the impact of commodity prices on our ceiling test limitation and proved reserves. The impact of price is only a single variable in the estimation of our proved reserves and other factors could have a significant impact on future reserves and the present value of future cash flows. The other factors that impact future estimates of proved reserves include, but are not limited to, extensions and discoveries, changes in costs, drilling results, revisions due to performance and other factors, changes in development plans and production. There are numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in subsequent periods and this pro forma estimate should not be construed as indicative of our development plans or future results.

 

The ceiling calculation is not intended to be indicative of the fair market value of our proved reserves or future results.  Impairment charges do not affect cash flow from operating activities but do adversely affect our net income and stockholders’ equity.  Any recorded impairment of oil and natural gas properties is not reversible at a later date.

 

25


 

U.S. Leaseholds

 

As of July 31, 2015, we have leased approximately 221,032 gross and 107,326 net acres in the Williston Basin, with approximately 191,150 gross and 78,961 net acres in our core focus area located predominantly in McKenzie and Williams Counties, North Dakota, and eastern Roosevelt and Sheridan Counties, Montana. The following table sets forth our gross and net acres of developed and undeveloped oil and natural gas leases:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Developed Acres

 

Undeveloped Acres

 

Total Acres

 

    

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

North Dakota

 

160,084

 

62,351

 

20,336

 

7,289

 

180,420

 

69,640

Montana

 

6,662

 

6,190

 

33,950

 

31,496

 

40,612

 

37,686

Total Williston Basin

 

166,746

 

68,541

 

54,286

 

38,785

 

221,032

 

107,326

 

Summary of Operating Results

 

The following table reflects the components of our production volumes, average realized prices, oil, natural gas and natural gas liquids revenues, and operating expenses for the periods indicated. No pro forma adjustments have been made for the acquisitions and divestitures of oil and natural gas properties, which will affect the comparability of the data below. The information set forth below is not necessarily indicative of future results.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended

 

For the Six Months Ended

 

 

July 31

 

July 31

Oil and Natural Gas Operations

    

2014

    

2015

 

2014

 

2015

Production volumes:

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil (Mbbls)

 

 

837

 

 

1,015

 

 

1,435

 

 

2,040

Natural gas (MMcf)

 

 

494

 

 

751

 

 

935

 

 

1,491

Natural gas liquids (Mbbls)

 

 

51

 

 

102

 

 

103

 

 

181

Total barrels of oil equivalent (Mboe)

 

 

970

 

 

1,242

 

 

1,694

 

 

2,470

 

 

 

 

 

 

 

 

 

 

 

 

 

Average daily production volumes (Boe/d)

 

 

10,543

 

 

13,500

 

 

9,359

 

 

13,646

 

 

 

 

 

 

 

 

 

 

 

 

 

Average realized prices:

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil ($ per Bbl)

 

$

90.78

 

$

51.71

 

$

90.82

 

$

47.52

Natural gas ($ per Mcf)

 

$

5.49

 

$

2.56

 

$

6.77

 

$

2.89

Natural gas liquids ($ per Bbl)

 

$

35.29

 

$

8.36

 

$

45.12

 

$

9.96

Total average realized price ($ per Boe)

 

$

82.94

 

$

44.50

 

$

83.42

 

$

41.72

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil, natural gas and natural gas liquids revenues (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

$

75,983

 

$

52,490

 

$

130,355

 

$

96,932

Natural gas

 

 

2,711

 

 

1,920

 

 

6,333

 

 

4,306

Natural gas liquids

 

 

1,812

 

 

853

 

 

4,652

 

 

1,803

Total oil, natural gas and natural gas liquids revenues

 

$

80,506

 

$

55,263

 

$

141,340

 

$

103,041

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating expenses (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

$

6,698

 

$

11,369

 

$

11,424

 

$

22,278

Gathering, transportation and processing

 

 

3,733

 

 

6,641

 

 

7,535

 

 

12,989

Production taxes

 

 

8,677

 

 

5,449

 

 

15,025

 

 

10,236

Oil and natural gas amortization expense

 

 

23,429

 

 

24,213

 

 

42,139

 

 

52,906

Impairment of oil and natural gas properties

 

 

 —

 

 

206,000

 

 

 —

 

 

398,000

Accretion of asset retirement obligations

 

 

40

 

 

90

 

 

65

 

 

147

Total operating expenses

 

$

42,577

 

$

253,762

 

$

76,188

 

$

496,556

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating expenses per Boe:

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

$

6.91

 

$

9.15

 

$

6.74

 

$

9.02

Gathering, transportation and processing

 

$

3.85

 

$

5.35

 

$

4.45

 

$

5.26

Production taxes

 

$

8.95

 

$

4.39

 

$

8.87

 

$

4.14

Oil and natural gas amortization expense

 

$

24.15

 

$

19.50

 

$

24.88

 

$

21.42

26


 

 

Comparison of Quarter Ended July 31, 2015 to Quarter Ended July 31, 2014

 

Oil, Natural Gas and Natural Gas Liquids Revenues.  Revenues from oil, natural gas and natural gas liquids for the three months ended July 31, 2015 decreased 31% to $55.3 million from $80.5 million for the three months ended July 31, 2014. Total production increased 28% due to our drilling and completion program. This increase in production was offset by a 46% decrease in weighted average realized prices from $82.94 per Boe for the three months ended July 31, 2014 to $44.50 per Boe for the three months ended July 31, 2015.

 

Lease Operating Expenses. Lease operating expense increased to $9.15 per Boe for the three months ended July 31, 2015 from $6.91 per Boe for the three months ended July 31, 2014. The cost increase is primarily the result of increased workover expenses and higher produced water disposal costs. We expect that lease operating expenses on a per Boe basis will continue to be higher in fiscal year 2016 than the prior year due to the decrease in our drilling and completion program compared to fiscal year 2015.

 

Gathering, Transportation and Processing. Gathering, transportation and processing expenses increased to $5.35 per Boe for the three months ended July 31, 2015 compared to $3.85 per Boe for the three months ended July 31, 2014.  We began transporting and processing our oil, natural gas, and natural gas liquids through Caliber’s facilities in fiscal year 2015. We often receive higher average realized prices by using Caliber’s facilities, partly offset by higher gathering, transportation, and process expenses.  We expect future expenses on a per Boe basis to be similar to those incurred to date in fiscal year 2016.

 

Production Taxes.  Production taxes decreased 37% in the second quarter of fiscal year 2016 to $5.4 million from $8.7 million for the second quarter of fiscal year 2015. The 31% decrease in oil, natural gas and natural gas liquids revenues for the three months ended July 31, 2015 versus the three months ended July 31, 2014 is the primary reason for the decrease.

 

Oil and Natural Gas Amortization.  Oil and natural gas amortization expense increased 3% to $24.2 million for the three months ended July 31, 2015 from $23.4 million for the three months ended July 31, 2014. On a per Boe basis, our oil and natural gas amortization expense decreased by $4.65 from $24.15 for the three months ended July 31, 2014 to $19.50 for the three months ended July 31, 2015 primarily due to the impairment recorded in the first quarter of fiscal year 2016.

 

Impairment Expense. During the second quarter of fiscal year 2016, we recorded a $206.0 million non-cash impairment of the carrying value of our proved oil and natural gas properties as a result of the ceiling test limitation. The impairment resulted primarily from lower realized oil prices. No provision for impairment was recorded during the second quarter of fiscal year 2015.

 

Oilfield Services Gross Profit. We formed RockPile with the strategic objective of having both greater control over one of our largest cost centers as well as to provide locally-sourced, high-quality completion services to TUSA and other operators in the Williston Basin. Since formation, RockPile has been focused on procuring new oilfield and complementary well completion equipment, building physical and supply chain infrastructure in North Dakota, recruiting and training employees, and establishing third-party customers. RockPile’s results of operations are affected by a number of variables including drilling and stimulation activity, pricing environment, service performance, equipment utilization, and the ability to secure and retain third-party customers. Pressure pumping direct costs include the cost of chemicals and proppant, labor (wages and benefits), logistics expenses, insurance, repairs and maintenance, and safety costs. Cost of goods sold as a percentage of revenue will vary based upon the pricing environment, completion design and equipment utilization.

 

For the three months ended July 31, 2015, RockPile performed hydraulic fracturing, cased-hole wireline, pressure pumping and workover services for TUSA and 9 third-party customers. Equipment utilized to perform these services consisted of four spreads, six wireline trucks, and five workover rigs. RockPile has increased its base of third-party customers; however, the competitive oilfield services pricing environment resulted in a 11% decrease in consolidated oilfield services revenues from $61.5 million for the three months ended July 31, 2014 to $54.5 million for the three months ended July 31, 2015. Hydraulic fracturing services resulted in 48 total well completions (9 for TUSA and 39 for third-parties) for the three months ended July 31, 2015 compared to 34 total well completions (15 for TUSA and 19 for third-parties) for the three months ended July 31, 2014.

 

27


 

The current competitive oilfield services pricing environment has resulted in a negative gross profit of $1.0 million for the quarter ended July 31, 2015 compared to a gross profit of $14.8 million for the quarter ended July 31, 2014, after eliminations of $5.3 million and $13.7 million of intercompany gross profit, respectively. We expect that the oilfield services pricing environment will continue to be very competitive as long as oil and natural gas prices remain near current levels, resulting in compressed or negative gross profits compared to the prior year.

 

The table below summarizes the RockPile contribution to our consolidated results for the quarters ended July 31, 2014 and 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended July 31, 2014

 

For the Three Months Ended July 31, 2015

(in thousands)

    

Oilfield Services

    

Eliminations

    

Consolidated

 

Oilfield Services

    

Eliminations

    

Consolidated

Revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oilfield services

 

$

102,055

 

$

(40,572)

 

$

61,483

 

$

69,431

 

$

(14,961)

 

$

54,470

Total revenues

 

 

102,055

 

 

(40,572)

 

 

61,483

 

 

69,431

 

 

(14,961)

 

 

54,470

Cost of sales

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oilfield services

 

 

68,867

 

 

(25,313)

 

 

43,554

 

 

56,353

 

 

(8,396)

 

 

47,957

Depreciation

 

 

4,690

 

 

(1,609)

 

 

3,081

 

 

8,718

 

 

(1,236)

 

 

7,482

Total cost of sales

 

 

73,557

 

 

(26,922)

 

 

46,635

 

 

65,071

 

 

(9,632)

 

 

55,439

Gross profit

 

$

28,498

 

$

(13,650)

 

$

14,848

 

$

4,360

 

$

(5,329)

 

$

(969)

 

General and Administrative Expenses.  The following table summarizes general and administrative expenses for the quarters ended July 31, 2014 and 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended July 31, 2014

 

For the Three Months Ended July 31, 2015

 

 

Exploration and 

 

Oilfield 

 

 

 

 

Consolidated

 

Exploration and 

 

Oilfield 

 

 

 

 

Consolidated

(in thousands)

    

Production

    

Services

    

Corporate

    

Total

  

Production

    

Services

    

Corporate

    

Total

Salaries and benefits

 

$

1,560

 

$

2,922

 

$

2,051

 

$

6,533

 

$

584

 

$

3,940

 

$

3,045

 

$

7,569

Stock-based compensation

 

 

343

 

 

127

 

 

1,337

 

 

1,807

 

 

375

 

 

84

 

 

3,167

 

 

3,626

Other general and administrative

 

 

2,882

 

 

2,329

 

 

540

 

 

5,751

 

 

349

 

 

1,034

 

 

2,011

 

 

3,394

Total

 

$

4,785

 

$

5,378

 

$

3,928

 

$

14,091

 

$

1,308

 

$

5,058

 

$

8,223

 

$

14,589

 

Total general and administrative expenses increased $0.5 million to $14.6 million for the three months ended July 31, 2015 compared to $14.1 million for the three months ended July 31, 2014. The increase in corporate general and administrative expenses is primarily a result of increased compensation and benefit costs for personnel due to the growth of the businesses, partly offset by lower other general and administrative expenses.

 

Commodity Derivatives.  We have entered into commodity derivative instruments, primarily costless collars and swaps, to reduce the effect of price changes on a portion of our future oil production. Our commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as derivative assets and liabilities. During the three months ended July 31, 2015, we recognized a gain of $25.0 million on our commodity derivative positions due to decreases in underlying crude oil prices, as compared to a loss of $0.9 million for the three months ended July 31, 2014. The fair values of the open commodity derivative instruments will continue to change in value until the transactions are settled. Therefore, we expect our net income to reflect the volatility of commodity price forward markets. Our cash flows will only be affected upon settlement of the transactions at the current market prices at that time. We recorded a realized commodity derivative gain of $17.0 million in the second quarter of fiscal year 2016, as compared to a realized commodity derivative loss of $3.0 million in the second quarter of fiscal year 2015.

 

Income from Equity Investment. Our equity investment in Caliber consists of Class A Units and equity derivative instruments. The Company recognized a $4.5 million gain on its equity investment derivatives in the second quarter of fiscal year 2016 compared to a $7.5 million loss during the second quarter of fiscal year 2015 related to the change in the fair value of the equity investment derivatives. In addition, during the three months ended July 31, 2015, the Company recognized $1.5 million for its share of Caliber’s net income for the period.  This income was offset by $0.3 million of intra-company gross profit recorded as a reduction of Triangle’s capitalized well costs attributable to services provided by

28


 

Caliber and capitalized by the Company, resulting in recognized income of $1.2 million. During the three months ended July 31, 2014, the Company recognized $0.8 million for its share of Caliber’s net income for the period.  This income was offset by $0.6 million of intra-company gross profit recorded as a reduction of Triangle’s capitalized well costs attributable to services provided by Caliber and capitalized by the Company, resulting in recognized income of $0.2 million.

 

Interest Expense.  The $9.9 million in interest expense for the three months ended July 31, 2015 consists of (i) approximately $1.1 million in interest related to the TUSA credit facility, (ii) approximately $1.7 million in accrued interest related to the Convertible Note, (iii) approximately $7.2 million in interest related to the TUSA 6.75% Notes, (iv) approximately $0.8 million in interest expense associated with RockPile’s credit facility and notes payable, and (v) approximately $0.1 million in interest expense related to our other debt, all net of approximately $1.0 million of capitalized interest which is generally incurred as exploratory wells are drilled and completed. Approximately $16.6 million of interest expense and capitalized interest was paid in cash.

 

The $4.2 million in interest expense for the three months ended July 31, 2014 consists of (i) approximately $1.8 million in interest related to the TUSA credit facility, (ii) approximately $1.6 million in accrued interest related to our Convertible Note, (iii) approximately $1.2 million in interest related to the TUSA 6.75% Notes, and (iv) approximately $0.6 million in interest expense associated with RockPile’s credit facility and notes payable, all net of approximately $1.0 million of capitalized interest. Approximately $3.1 million of interest expense and capitalized interest was paid in cash.

 

Income Taxes.  We recorded a full valuation allowance against our net deferred tax assets in the first quarter of fiscal year 2016.  Therefore, we had no income tax provision for the three months ended July 31, 2015 compared to expense of $10.3 million for the three months ended July 31, 2014.

 

As previously noted, the carrying value of our oil and natural gas properties exceeded the calculated value of the ceiling limitation resulting in impairments of $192.0 million for the three months ended April 30, 2015 and $206.0 million for the three months ended July 31, 2015. These impairments resulted in Triangle having three years of cumulative historical pre-tax losses and a net deferred tax asset position. Additionally, Triangle will likely be required to recognize additional impairments of its oil and natural gas properties in future periods if oil and natural gas prices remain at current levels or continue to decline and such impairments will likely be material. Triangle also had NOLs for federal income tax purposes of $136.9 million at January 31, 2015. These losses and expected future losses were a key consideration that led Triangle to provide a valuation allowance against its net deferred tax assets as of April 30, 2015 and July 31, 2015 since it cannot conclude that it is more likely than not that its net deferred tax assets will be fully realized in future periods.

 

The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. At each reporting period, management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment. Future events or new evidence which may lead the Company to conclude that it is more likely than not that its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings; sustained or continued improvements in oil prices; and taxable events that could result from one or more transactions. The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods.

 

As long as the Company concludes that it will continue to have a need for a valuation allowance against its net deferred tax assets, the Company likely will not have any additional income tax expense or benefit other than for federal alternative minimum tax expense, a release of a portion of the valuation allowance for net operating loss carryback claims or for state income taxes.

 

Comparison of the Six Month Period Ended July 31, 2015 to the Six Month Period Ended July 31, 2014

 

Oil, Natural Gas and Natural Gas Liquids Revenues.  Revenues from oil, natural gas and natural gas liquids for the six months ended July 31, 2015 decreased 27% to $103.0 million from $141.3 million for the six months ended July 31, 2014. Total production increased 46% for the six months ended July 31, 2015 compared to the six months ended July 31, 2014 due to our drilling and completion program. This increase in production was offset by a 50% decrease in weighted average realized prices from $83.42 per Boe for the six months ended July 31, 2014 to $41.72 per Boe for the six months ended July 31, 2015.

 

29


 

Lease Operating Expenses.  Lease operating expense increased to $9.02 per Boe for the six months ended July 31, 2015 from $6.74 per Boe for the six months ended July 31, 2014. The cost increase is primarily the result of increased workover expenses and higher produced water disposal costs. We expect that lease operating expenses on a per Boe basis will continue to be higher in fiscal year 2016 than the prior year due to the decrease in our drilling and completion program compared to fiscal year 2015.

 

Gathering, Transportation and Processing. Gathering, transportation and processing expenses increased to $5.26 per Boe for the six months ended July 31, 2015 compared to $4.45 per Boe for the six months ended July 31, 2014. We often receive higher average realized prices by using Caliber’s facilities, partly offset by higher gathering, transportation, and process expenses.  We expect future expenses on a per Boe basis to be similar to those incurred to date in fiscal year 2016.

 

Production Taxes.  Production taxes decreased 32% in the first six months of fiscal year 2016 to $10.2 million from $15.0 million for the first six months of fiscal year 2015. The 27% decrease in oil, natural gas and natural gas liquids revenues for the six months ended July 31, 2015 versus the six months ended July 31, 2014 is the primary reason for the decrease.

 

Oil and Natural Gas Amortization.  Oil and natural gas amortization expense increased 26% to $52.9 million for the six months ended July 31, 2015 from $42.1 million for the six months ended July 31, 2014. The increase is primarily related to increased production in the first six months of fiscal year 2016 as compared to the first six months of fiscal year 2015. On a per Boe basis, our oil and natural gas amortization expense decreased by $3.46 from $24.88 for the six months ended July 31, 2014 to $21.42 for the six months ended July 31, 2015 primarily due to increases in proved reserves from successful development and field extensions, and to the impairment recorded in the first quarter of fiscal year 2016.

 

Impairment Expense. During the first six months of fiscal year 2016, we recorded a $398.0 million non-cash impairment of the carrying value of our proved oil and natural gas properties as a result of the ceiling test limitation. The impairment resulted primarily from lower realized oil prices. No provision for impairment was recorded during the first six months of fiscal year 2015.

 

Oilfield Services Gross Profit.  For the six months ended July 31, 2015, RockPile performed hydraulic fracturing, cased-hole wireline, pressure pumping and workover services for TUSA and 14 third-party customers. Equipment utilized to perform these services consisted of four spreads, six wireline trucks, and five workover rigs. RockPile has increased its base of third-party customers, and consolidated oilfield services revenues increased 24% from $100.4 million for the six months ended July 31, 2014 to $125.0 million for the six months ended July 31, 2015. Hydraulic fracturing services resulted in 103 total well completions (14 for TUSA and 89 for third-parties) for the six months ended July 31, 2015 compared to 60 total well completions (24 for TUSA and 36 for third-parties) for the six months ended July 31, 2014.

 

The current competitive oilfield services pricing environment has resulted in a negative gross profit of $3.3 million for the six months ended July 31, 2015 compared to a gross profit of $23.7 million for the six months ended July 31, 2014, after eliminations of $8.2 million and $18.9 million of intercompany gross profit, respectively. We expect that the oilfield services pricing environment will continue to be very competitive as long as oil and natural gas prices remain near current levels, resulting in compressed or negative gross profits compared to the prior year.

 

The table below summarizes the RockPile contribution to our consolidated results for the six months ended July 31,  2014 and 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Six Months Ended July 31, 2014

 

For the Six Months Ended July 31, 2015

(in thousands)

    

Oilfield Services

    

Eliminations

    

Consolidated

 

Oilfield Services

    

Eliminations

    

Consolidated

Revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oilfield services

 

$

163,487

 

$

(63,056)

 

$

100,431

 

$

150,025

 

$

(25,045)

 

$

124,980

Total revenues

 

 

163,487

 

 

(63,056)

 

 

100,431

 

 

150,025

 

 

(25,045)

 

 

124,980

Cost of sales

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oilfield services

 

 

112,578

 

 

(41,314)

 

 

71,264

 

 

126,939

 

 

(14,756)

 

 

112,183

Depreciation

 

 

8,280

 

 

(2,809)

 

 

5,471

 

 

18,207

 

 

(2,066)

 

 

16,141

Total cost of sales

 

 

120,858

 

 

(44,123)

 

 

76,735

 

 

145,146

 

 

(16,822)

 

 

128,324

Gross profit

 

$

42,629

 

$

(18,933)

 

$

23,696

 

$

4,879

 

$

(8,223)

 

$

(3,344)

 

30


 

General and Administrative Expenses.  The following table summarizes general and administrative expenses for the six months ended July 31, 2014 and 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Six Months Ended July 31, 2014

 

For the Six Months Ended July 31, 2015

 

 

Exploration and

 

Oilfield

 

 

 

 

Consolidated

 

Exploration and 

 

Oilfield 

 

 

 

 

Consolidated

(in thousands)

    

Production

    

Services

    

Corporate

    

Total

 

Production

    

Services

    

Corporate

    

Total

Salaries and benefits

 

$

2,801

 

$

5,660

 

$

4,333

 

$

12,794

 

$

925

 

$

8,769

 

$

6,298

 

$

15,992

Stock-based compensation

 

 

738

 

 

217

 

 

2,860

 

 

3,815

 

 

696

 

 

135

 

 

5,303

 

 

6,134

Other general and administrative

 

 

4,419

 

 

4,688

 

 

1,776

 

 

10,883

 

 

756

 

 

2,831

 

 

3,735

 

 

7,322

Total

 

$

7,958

 

$

10,565

 

$

8,969

 

$

27,492

 

$

2,377

 

$

11,735

 

$

15,336

 

$

29,448

 

Total general and administrative expenses increased $1.9 million to $29.4 million for the six months ended July 31, 2015 compared to $27.5 million for the six months ended July 31, 2014. The increase in corporate general and administrative expenses is primarily a result of increased compensation and benefit costs for personnel due to the growth of the businesses, partly offset by lower other general and administrative expenses.

 

Commodity Derivatives.  We have entered into commodity derivative instruments, primarily costless collars and swaps, to reduce the effect of price changes on a portion of our future oil production. Our commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as derivative assets and liabilities. During the six months ended July 31, 2015, we recognized a gain of $11.1 million on our commodity derivative positions due to decreases in underlying crude oil prices, as compared to a loss of $6.4 million for the six months ended July 31, 2014. The fair values of the open commodity derivative instruments will continue to change in value until the transactions are settled. Therefore, we expect our net income to reflect the volatility of commodity price forward markets. Our cash flows will only be affected upon settlement of the transactions at the current market prices at that time. We recorded a realized commodity derivative gain of $36.5 million in the first six months of fiscal year 2016, as compared to a realized commodity derivative loss of $3.8 million in the first six months of fiscal year 2015.

 

Income from Equity Investment.  Our equity investment in Caliber consists of Class A Units and equity derivative instruments. The Company recognized a $4.5 million gain on its equity investment derivatives in the first six months of fiscal year 2016 compared to a $2.9 million gain during the first six months of fiscal year 2015 related to the change in the fair value of the equity investment derivatives. In addition, during the six months ended July 31, 2015, the Company recognized $1.9 million for its share of Caliber’s net income for the period. This income was offset by $0.5 million of intra-company gross profit recorded as a reduction of Triangle’s capitalized well costs attributable to services provided by Caliber and capitalized by the Company, resulting in recognized income of $1.4 million. During the six months ended July 31, 2014, the Company recognized $0.9 million for its share of Caliber’s net income for the period. This income was offset by $0.8 million of intra-company gross profit recorded as a reduction of Triangle’s capitalized well costs attributable to services provided by Caliber and capitalized by the Company, resulting in a recognized income of $0.1 million. In addition, we recognized a gain in the first six months of fiscal year 2016 of $2.9 million related to Caliber’s issuance of 2,720,000 Class A Units to FREIF.  

 

Interest Expense.  The $19.0 million in interest expense for the six months ended July 31, 2015 consists of (i) approximately $2.0 million in interest related to the TUSA credit facility, (ii) approximately $3.4 million in accrued interest related to the Convertible Note, (iii) approximately $14.5 million in interest related to the TUSA 6.75% Notes, (iv) approximately $1.6 million in interest expense associated with RockPile’s credit facility and notes payable, and (v) approximately $0.2 million in interest expense related to our other debt, all net of approximately $2.7 million of capitalized interest which is generally incurred as exploratory wells are drilled and completed. Approximately $18.8 million of interest expense and capitalized interest was paid in cash.

 

The $6.9 million in interest expense for the six months ended July 31, 2014 consists of (i) approximately $3.1 million in interest related to the TUSA credit facility, (ii) approximately $3.3 million in accrued interest related to our Convertible Note, (iii) approximately $1.2 million in interest related to the TUSA 6.75% Notes and (iv) approximately $1.1 million in interest expense associated with RockPile’s credit facility and notes payable, all net of approximately $1.8 million of capitalized interest. Approximately $4.7 million of interest expense and capitalized interest was paid in cash.

31


 

 

Income Taxes.  As noted above, we recorded a full valuation allowance against our net deferred tax assets in the first six months of fiscal year 2016, and we recognized a benefit of $53.4 million compared to an expense of $20.4 million for the six months ended July 31, 2014.

 

Liquidity and Capital Resources

 

Our liquidity is highly dependent on the prices we receive for the oil, natural gas and natural gas liquids we produce. Commodity prices are market driven and are historically volatile. Prices received for production heavily influence our revenue, cash flows, profitability, access to capital and future rate of growth. In addition, commodity prices received by exploration and production companies in the Williston Basin affect the level of drilling activity there, and therefore may affect the demand for services provided by RockPile and/or Caliber.

 

In the first six months of fiscal year 2016, our average realized price for oil was $47.52 per barrel, a decrease of 48% over the average realized price for the first six months of fiscal year 2015. This reflected the dramatic decrease in the price of oil that occurred over the second half of fiscal year 2015 and has continued through the first six months of fiscal year 2016. Future prices for oil will likely continue to fluctuate due to supply and demand factors, seasonality and other geopolitical and economic factors. We manage the impact that volatility in commodity prices has on our liquidity by periodically hedging a portion of our oil production to mitigate our potential exposure to price declines and maintaining flexibility in our capital investment program.

 

As of July 31, 2015, we had cash of approximately $45.9 million consisting primarily of cash held in bank accounts, as compared to approximately $67.9 million at January 31, 2015. At July 31, 2015, we also had available borrowing capacity of $177.7 million under the TUSA credit facility and $63.1 million under the RockPile credit facility.

 

As of July 31, 2015, we had approximately $837.7 million of debt outstanding, consisting of $425.9 million for the TUSA 6.75% Notes, $139.3 million for the Convertible Note, $172.3 million for the TUSA credit facility, $86.9 million for the RockPile credit facility, and $13.3 million for other notes and mortgages.

 

Cash Flows

 

The following is a summary of our changes in cash and cash equivalents for the six months ended July 31, 2014 and 2015:

 

 

 

 

 

 

 

 

 

 

For the Six Months Ended July 31,

(in thousands)

    

2014

    

2015

Net cash provided by operating activities

 

$

61,846

 

$

80,045

Net cash used in investing activities

 

 

(308,448)

 

 

(135,827)

Net cash provided by financing activities

 

 

272,379

 

 

33,781

Net increase (decrease) in cash and equivalents

 

$

25,777

 

$

(22,001)

 

Net Cash Provided by Operating Activities.  Cash flows provided by operating activities were $80.0 million for the six months ended July 31, 2015, compared to $61.8 million for the six months ended July 31, 2014. Cash flows from operating activities were unfavorably impacted in the six months ended July 31, 2015 by lower realized oil prices and the competitive oilfield services pricing environment compared to the six months ended July 31, 2014, offset by favorable changes in current assets and current liabilities in the six months ended July 31, 2015.

 

Net Cash Used in Investing Activities.  During the six months ended July 31, 2015, we used $135.8 million in cash in investing activities compared to $308.4 million during the six months ended July 31, 2014. During the six months ended July 31, 2015 and 2014, we used $128.7 million and $149.5 million, respectively, on oil and natural gas property expenditures and $0.2 million and $131.4 million, respectively, to acquire oil and natural gas properties. During the six months ended July 31, 2015 and 2014, we also spent $8.7 million and $24.6 million, respectively, on purchases of oilfield services equipment and $4.2 million and $3.1 million, respectively, on other property and equipment, primarily facility construction and improvements. During the six months ended July 31, 2015, we received net proceeds of $6.0 million from the sale of a salt water disposal well to Caliber.

 

32


 

Net Cash Provided by Financing Activities. Cash flows provided by financing activities for the six months ended July 31, 2015 totaled $33.8 million, as compared to $272.4 million for the six months ended July 31, 2014. Our primary source of cash from financing activities during the six months ended July 31, 2015 came from $35.0 million in net borrowings from our credit facilities. Our primary financing activities during the six months ended July 31, 2014 included the issuance of $450.0 million of the TUSA 6.75% Notes and net repayments on our credit facilities of $164.9 million.

 

Capital Requirements Outlook

 

Our cash flows from operations for the first six months of fiscal year 2016 were insufficient to cover our capital requirements, and we continued to rely on external financing activities. We believe that the lag time between initial investment and cash flows from such investment is typical of the oil and natural gas industry where upfront costs are significant and cash flows are delayed. This holds true across our businesses, including drilling and completion costs for TUSA and equipment costs for RockPile. While we are not obligated to fund any further equity commitment for Caliber, the lag time between investment in operations and cash flows is exacerbated in the midstream space where initial construction costs and project timelines are substantial. In a higher oil and natural gas pricing environment such as we experienced in recent years, we expect that our cash flows from operations would increase significantly as additional TUSA oil and natural gas wells commence production, RockPile’s oilfield services increase, and Caliber’s gathering and processing system becomes more fully utilized. However, we expect that current depressed oil and natural gas prices, which have temporarily deferred our drilling program and created a very competitive oilfield services market, will continue to limit our cash flows from operations in upcoming quarters compared to the same periods in fiscal year 2015.

 

In response to the current oil and natural gas pricing environment, we have significantly reduced capital expenditures, and we may further adjust such expenditures as market dynamics warrant. We will likely remain dependent on borrowings under our credit facilities and, to a lesser extent, potential additional financings to fund the difference between cash flows from operations and our capital expenditures budget and other contractual commitments. Although we expect that our operating cash flows and availability under our credit facilities will be largely sufficient for our capital requirements, any additional shortfall may be financed through additional debt or equity instruments. There can be no assurance that we will achieve our anticipated future cash flows from operations, that credit will be available when needed, or that we would be able to complete alternative transactions in the capital markets if needed.

 

We may continue to pursue significant acquisition opportunities, which may require additional financing. Our ability to obtain additional financing on commercially reasonable terms is dependent on a number of factors, many of which we cannot control, including changes in our credit rating, interest rates, market perceptions of us and the oil and natural gas industry, and tax burdens due to new tax laws.

 

If our existing and potential sources of liquidity are not sufficient to allow us to satisfy our commitments and to undertake our currently planned expenditures, particularly if commodity prices remain depressed for an extended period of time, we have the flexibility to further alter our development program or divest assets. Our operatorship of much of our acreage allows us the ability to adjust our drilling and completions schedules in response to changes in commodity prices or the oilfield services environment. Further, if we are not successful in obtaining sufficient funding on a timely basis on terms acceptable to us, we may be required to curtail our planned expenditures and/or restructure our operations, which may reduce anticipated future cash flows from operations.

 

Sources of Capital 

 

Cash flows from operations.  Our produced volumes have increased significantly over the past three years as a result of the successful development of our operated properties. However, due to the current depressed oil and natural gas pricing environment, we have temporarily deferred our drilling program, and we plan to delay the completion of certain wells subject to a number of factors, including the price of oil and natural gas at the time, oilfield services and materials costs, and the availability of third party work for RockPile. Consequently, our production volume growth is expected to slow throughout the remainder of fiscal year 2016, and the benefit we receive from any increased production is likely to be less than it was in comparable periods of fiscal year 2015 due to lower realized prices. If oil and natural gas prices recover sufficiently during the remainder of fiscal year 2016, we may increase drilling and completion expenditures, which we expect would increase production volumes and cash flows from operations.

 

Cash flows from our oilfield services segment decreased significantly in the first six months of fiscal year 2016 primarily due to efforts to remain competitive in the current oil and natural gas pricing environment by significantly

33


 

reducing fees that RockPile charges to its customers. As a result of the margin compression on fees charged for services, as well as the likelihood for lower utilization of RockPile services by customers slowing the pace of their development operations, we anticipate that RockPile’s cash flows from operations throughout the remainder of fiscal year 2016 will be substantially lower than comparable periods in fiscal year 2015.

 

Credit facilities. As of July 31, 2015, our maximum credit available under the TUSA credit facility was $1.0 billion, subject to a borrowing base of $350.0 million. As of July 31, 2015, we had $177.7 million of borrowing capacity available. The borrowing base under the TUSA credit facility is subject to redetermination on a semi-annual basis by May 1 and November 1. In addition, each of TUSA and the lenders may request an unscheduled borrowing base redetermination twice during each calendar year. We anticipate limited, if any, borrowing base growth in fiscal year 2016, and our borrowing base may be further reduced if oil and natural gas prices do not rebound. As of July 31, 2015, our maximum credit available under the RockPile credit facility was $150.0 million, and we had $63.1 million of borrowing capacity available. Notwithstanding a potential additional borrowing base reduction under the TUSA credit facility, we expect that the substantial borrowing capacity available under our credit facilities will be sufficient to finance any difference between our cash flows from operations and our anticipated capital expenditures.

 

Securities Offerings. Historically, we have financed our operations, property acquisitions and other capital investments in part from the proceeds of public and private offerings of our equity and debt securities. We may from time to time offer debt securities, common stock, preferred stock, warrants and other securities, or any combination of such securities, in amounts, at prices and on terms announced when and if the securities are offered. The specifics of any future public offerings, along with the use of proceeds of any securities offered, will be described in detail in a prospectus or a prospectus supplement at the time of such offering.

 

Asset Sales.  In the past, our acquisition activities have significantly outpaced our asset sales, which have been generally limited to small, opportunistic divestitures or exchanges of leasehold interests. In the current depressed commodity pricing environment, we are strategically reviewing our assets to consider monetizing those that may garner attractive prices or are peripheral to our core businesses. Such assets include, but are not limited to, non-operated acreage, equity investments, equipment, and other real property interests. If commodity prices remain depressed for an extended period of time and we are unable to fund our operations from other sources of capital, we may be forced to sell portions of our operated core acreage or other assets at distressed prices.

 

Commodity Derivative Instruments

 

We utilize various derivative instruments in connection with anticipated crude oil sales to reduce the impact of product price fluctuations. Currently, we utilize costless collars and swaps. Current period settlements on commodity derivative instruments impact our liquidity, since we are either paying cash to, or receiving cash from, our counterparties. If actual commodity prices are higher than the fixed or ceiling prices in our derivative instruments, our cash flows will be lower than they would be if we had no derivative instruments. Conversely, if actual commodity prices are lower than the fixed or floor prices in our derivative instruments, our cash flows will be higher than if we had no derivative instruments.

 

Working Capital 

 

As part of our cash management strategy, we periodically use available funds to reduce amounts borrowed under our credit facilities. However, due to certain restrictive covenants contained in our credit facilities regarding our ability to dividend or otherwise transfer funds from the borrower to Triangle, we seek to maintain sufficient liquidity at Triangle to manage foreseeable and unforeseeable consolidated cash requirements. Since our principal source of operating cash flows (proved reserves to be produced in later periods) is not considered working capital, we often have low or negative working capital. Our working capital was $6.9 million as of July 31, 2015, as compared to $37.7 million at January 31, 2015.

 

Off-Balance Sheet Arrangements

 

We have no off-balance sheet arrangements that have or are reasonably likely to have a material current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

34


 

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

Commodity Price Risk.  Our primary market risk is related to changes in oil prices. The market price of oil has been highly volatile and is likely to continue to be highly volatile in the future, which will impact our prospective revenues from the sale of products or properties. Currently, we utilize swaps and costless collars to reduce the effect of price changes on a portion of our future oil production. We do not enter into derivative instruments for trading purposes. For accounting purposes, we mark our derivatives to fair value and recognize the changes in fair value under the gain (loss) from derivative activities line on the consolidated statements of operations.

 

We use costless collars to establish floor and ceiling prices on our anticipated future oil production. We neither receive nor pay net premiums when we enter into these arrangements. These contracts are settled on a monthly basis. When the settlement price (the market price for oil or natural gas during the settlement period) for a period is above the ceiling price, we pay our counterparty. When the settlement price for a period is below the floor price, our counterparty is required to pay us.

 

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. TUSA is currently a party to derivative contracts with four counterparties. The Company has a netting arrangement with each counterparty that provides for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination. Although the instruments are valued using indices published by established exchanges, the instruments are traded directly with the counterparty. The derivative contracts may be terminated by a non-defaulting party in the event of a default by one of the parties to the agreement.

 

The objective of the Company’s use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil prices and to manage its exposure to commodity price risk. While the use of these derivative instruments reduces the downside risk of adverse price movements, these instruments may also limit the Company’s ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional forecasted production, restructure or reduce existing derivative contracts, or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions.

 

The Companys commodity derivative contracts as of July 31, 2015 are summarized below:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Contract

 

 

 

Quantity

 

Weighted Average

 

Weighted Average

 

Weighted Average

 

    

Type

    

Basis (1)

    

(Bbl/d)

 

Put Strike

 

Call Strike

  

Price

August 1, 2015 to January 31, 2016

 

Collar

 

NYMEX

 

2,739

 

$

85.45

 

$

98.20

 

 

 

August 1, 2015 to January 31, 2016

 

Swap

 

NYMEX

 

1,755

 

 

 

 

 

 

 

$

60.22

February 1, 2016 to January 31, 2017

 

Swap

 

NYMEX

 

2,746

 

 

 

 

 

 

 

$

60.23

(1)

NYMEX refers to West Texas Intermediate crude oil prices at Cushing, Oklahoma as quoted on the New York Mercantile Exchange.

 

In August 2015, the Company unwound certain commodity derivative swap contracts and realized a gain of $9.3 million.  The early settled contracts were for 2,000 barrels of oil per day at an average fixed price of $60.34 for the period from January 1, 2016 to December 31, 2016.

 

We have elected not to apply cash flow hedge accounting to any of our derivative transactions and we therefore recognize mark-to-market gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income for those commodity derivatives that would qualify as cash flow hedges.

 

All derivative instruments are recorded on the balance sheet at fair value.  Fair value is generally determined based on the difference between the fixed contract price and the underlying market price at the determination date.  Changes in the fair value of derivatives are recorded in commodity derivative (gains) losses on the consolidated statements of operations.  As of July 31, 2015, the fair value of our commodity derivatives was a net asset of $29.4 million.  An assumed increase of 10% in the forward commodity prices used in the July 31, 2015 valuation of our derivative instruments would result in a net derivative asset of approximately $20.7 million at July 31, 2015. Conversely, an assumed decrease of 10% in forward commodity prices would result in a net derivative asset of approximately $37.9 million at July 31, 2015.

 

35


 

Interest Rate Risk.  As of July 31, 2015, we had $350.0 million of borrowing availability under the TUSA credit facility, of which $172.3 million was drawn at quarter-end. The credit facility bears interest at variable rates. Assuming we had the maximum amount outstanding at July 31, 2015 under the TUSA credit facility of $350.0 million, a 1.0% increase in interest rates would result in additional annualized interest expense of $3.5 million.

 

As of July 31, 2015, RockPile had an aggregate of $150.0 million available for borrowing under its credit facility of which approximately $86.9 million of principal was outstanding as of such date. The credit facility bears interest at variable rates. Assuming RockPile had the maximum amount outstanding at July 31, 2015 under the credit facility of $150.0 million, a 1.0% interest rate increase would result in additional annualized interest expense of approximately $1.5 million.

 

The Convertible Note and the TUSA 6.75% Notes bear interest at fixed rates.

 

ITEM 4.  CONTROLS AND PROCEDURES

 

Disclosure Controls and Procedures

 

Our management, with the participation of Jonathan Samuels, our President and Chief Executive Officer, and Justin Bliffen, our Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of July 31, 2015. Based on the evaluation, those officers believe that:

 

·

our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms; and

 

·

our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 was accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

 

Changes in Internal Control over Financial Reporting

 

There has not been any change in our internal control over financial reporting that occurred during the quarterly period ended July 31, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

36


 

PART II.  OTHER INFORMATION

 

Item 1.  Legal Proceedings.

 

From time to time, we may become involved in various lawsuits and legal proceedings which arise in the ordinary course of business. Litigation is subject to inherent uncertainties, and an adverse result in these or other matters may arise from time to time that may harm our business. We are currently not aware of any legal proceedings or claims that we believe will have, individually or in the aggregate, a material adverse effect on our business, financial condition or operating results.

 

Item 1A.  Risk Factors.

 

There have been no material changes to the risk factors set forth in our Fiscal 2015 Form 10-K. Those risks, in addition to the other information set forth in this Quarterly Report on Form 10-Q and in our other filings with the SEC, could materially affect our business, financial condition or results of operations. Additional risks and uncertainties not currently known to us or that we deem to be immaterial could also materially adversely affect our business, financial condition or results of operations.

 

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds.

 

The following table summarizes our purchases of shares of our common stock during the fiscal quarter ended July 31, 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Maximum number

 

 

 

 

 

 

 

 

Total number of

 

of shares that may

 

 

 

Total Number

 

Average

 

shares purchased

 

yet be purchased

 

 

    

of Shares

    

Price Paid

    

as part of publicly

    

under the plans

 

 

 

Purchased

 

Per Share

 

announced plans (2)

 

at month end

 

May 1, 2015 to May 31, 2015

 

32,896

 

$

5.51

 

 —

 

5,160,820

(3)  

June 1, 2015 to June 30, 2015

 

5,524

 

 

5.22

 

 —

 

5,374,890

(4)  

July 1, 2015 to July 31, 2015

 

13,264

 

 

4.18

 

 —

 

5,374,890

 

 

 

51,684

(1)  

$

5.14

 

 —

 

 

 


(1)

Shares of common stock surrendered by certain employees to the Company in satisfaction of their tax liability upon the vesting of their restricted stock units. The number of shares of common stock actually issued to such employees upon the vesting of their restricted stock units was net of the shares surrendered in satisfaction of their tax liability. The withheld shares are not issued or considered common stock repurchased under the repurchase program described below.

 

(2)

As reported in Current Reports on Form 8-K filed with the SEC on September 11, 2014 and October 17, 2014, the Company’s Board of Directors approved a program authorizing the repurchase of outstanding shares of the Company’s common stock in amounts equal to the aggregate of (i) $25.0 million of the Company’s common stock (Tranche 1), (ii) up to the number of shares of common stock authorized for issuance under the Company’s 2014 Equity Incentive Plan and its CEO Stand-Alone Stock Option Agreement (Tranche 2), and (iii) up to the number of shares of common stock potentially issuable, at any given time, pursuant to the paid-in-kind interest accrued on the Convertible Note (Tranche 3). Shares of common stock repurchased under the program may be repurchased from time to time, in amounts and at prices that the Company deems appropriate, subject to market and business conditions and other considerations. The repurchase program may be executed using open market purchases pursuant to Rule 10b-18 under the Exchange Act, pursuant to a Rule 10b5-1 plan, in privately negotiated agreements, or other transactions. The repurchase program has no expiration date and may be suspended or discontinued at any time without prior notice. As of July 31, 2015, an aggregate of 11,431,744 shares of the Company’s common stock have been repurchased under the program.

 

(3)

Includes the number of shares of common stock remaining available for repurchase pursuant to Tranche 2, plus the number of shares of common stock available for repurchase pursuant to Tranche 3 based on the paid-in-kind interest

37


 

accrued on the Convertible Note as of June 30, 2015. All shares of common stock authorized for repurchase under Tranche 1 have been exhausted.

 

(4)

Includes an additional 214,070 shares of common stock potentially issuable pursuant to the paid-in-kind interest added to the principal balance of the Convertible Note on June 30, 2015.

 

Item 3.  Defaults Upon Senior Securities.

 

None.

 

Item 4.  Mine Safety Disclosures.

 

Not Applicable.

 

Item 5.  Other Information.

 

Not Applicable.

38


 

Item 6.  Exhibits

 

 

 

 

3.1

 

Certificate of Incorporation of Triangle Petroleum Corporation, filed as Exhibit 3.1 to the Annual Report on Form 10-K filed with the Securities and Exchange Commission on April 17, 2014 and incorporated herein by reference.

 

 

 

3.2

 

Certificate of Amendment to the Certificate of Incorporation of Triangle Petroleum Corporation, filed as Exhibit 3.2 to the Annual Report on Form 10-K filed with the Securities and Exchange Commission on April 17, 2014 and incorporated herein by reference.

 

 

 

3.3

 

Bylaws of Triangle Petroleum Corporation, filed as Exhibit 3.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on December 3, 2012 and incorporated herein by reference.

 

 

 

31.1*

 

Certification of Chief Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 

 

 

31.2*

 

Certification of Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 

 

 

32.1*

 

Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

 

 

101.INS*

 

XBRL Instance Document

 

 

 

101.SCH*

 

XBRL Taxonomy Extension Schema Document

 

 

 

101.CAL*

 

XBRL Taxonomy Extension Calculation Linkbase Document

 

 

 

101.LAB*

 

XBRL Taxonomy Extension Label Linkbase Document

 

 

 

101.PRE*

 

XBRL Taxonomy Extension Presentation Linkbase Document

 

 

 

101.DEF*

 

XBRL Taxonomy Extension Definition Linkbase Document

 


 

Filed herewith.

39


 

SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

 

 

 

TRIANGLE PETROLEUM CORPORATION

 

 

 

Date:  September 8,  2015

 

By: 

 

/s/ JONATHAN SAMUELS

 

Jonathan Samuels

 

President and Chief Executive Officer

 

 

USTIN,  2015

 

 

 

Date:  September 8,  2015

 

By: 

 

/s/ JUSTIN BLIFFEN

 

Justin Bliffen

 

Chief Financial Officer

 

 

 

 

 

40